Aging Power Delivery Infrastructures

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Aging Power Delivery Infrastructures

Infrastructures H. Lee Willis V. Welch Gregory V. Randall R. Schrieber ABB Power T&D Company Company Inc. Inc. Raleigh,

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Aging Power Delivery Infrastructures Infrastructures H. Lee Willis V. Welch Gregory V. Randall R. Schrieber ABB Power T&D Company Company Inc. Inc. Raleigh, North Carolina

n

MARCEL M A R C E L

MARCEL DEKKER, INC. MARCEL DEKKER, INC.

D E K K E R DEKKER

Copyright © 2001 by Taylor & Francis Group, LLC

NEW YORK' BASEL NEW YORK • BASEL

ISBN: 0-8247-0539-4 printed on acid-free acid-free paper. This book is printed Headquarters Marcel Dekker, Inc. York, NY 10016 270 Madison Avenue, New York, tel: 212-696-9000: 212-696-9000; fax: fax: 212-685-4540 Eastern Hemisphere Distribution Distribution Marcel Dekker AG BaseL Switzerland Switzerland Hutgasse 4, Postfach 812, CH-400 CH-40011 Basel, fax: 41-61-261-8896 tel: 41-61-261-8482; 41-61-261-8482: fax: World Wide Web http://www.dekker.com

quantities. For more inforThe publisher offers discounts on this book when ordered in bulk quantities. mation, write (0 to Special Sales/Professional Marketing at the headquarters address above. mation. Inc. All Rights Copyright © 2001 by Marcel Dekker, Inc. Rights Reserved. Neither this transmitted in any form or by any this book nor any part may be reproduced or transmitted means, electronic electronic or mechanical, mechanical, including photocopying. photocopying, microfilming, and recording. recording, or means. by any information storage and retrieval system, without permission in writing the without permission writing from (he publisher. Current printing printing (last digit): 1 0 9 8 7 6 5 4 3 22 1 10

PRINTED IN THE UNITED STATES OF AMERICA

Copyright © 2001 by Taylor & Francis Group, LLC

POWER ENGINEERING ENGINEERING Series Editor

H. Lee Willis Electric Systems Systems Technology ABB Electric Technology Institute Institute Raleigh, North Carolina Carolina

1. Power Distribution Planning Reference Book, H. Lee Willis Willis 2. Transmission Network Network Protection: Theory and Practice, Y. Y. G. Paithankar Paithankar Electrical Insulation Insulation in Power Systems, N. N. H. H. Malik, A. A. AI-Arainy, AI-Arainy, 3. Electrical and M. I.I. Qureshi 4. Electrical Electrical Power Equipment Equipment Maintenance and and Testing, Paul Gill Relaying: Principles and and Applications, Second Second Edition, J. J. 5. Protective Relaying: Lewis Blackburn 6. Understanding Electric Utilities and and De-RegUlation, De-Regulation, Lorrin Philipson and and H. Lee Willis Willis 7. Electrical Electrical Power Cable Cable Engineering, Engineering, William William A. Thue 8. Electric Electric Systems, Dynamics, and and Stability with Artificial Intelligence Applications, James A. Momoh Momoh and Mohamed Mohamed E. EI-Hawary E. El-Hawary Insulation Coordination for Power Systems, Andrew R. Hileman 9. Insulation Andrew R. Power Generation: Planning and Evaluation, H. Willis 10. Distributed Power H. Lee Willis and Walter G. G. Scott 11. Electric Power System Applications of Optimization, Optimization, James A. Momoh 12. Aging Power Delivery Infrastructures, H. V. H. Lee Willis, Gregory Gregory V. and Randall R. R. Schrieber Welch, and

ADDITIONAL VOLUMES VOLlJMES IN PREPARATION

Copyright © 2001 by Taylor & Francis Group, LLC

Series Introduction Power within Power engineering engineering is the oldest oldest and most traditional of of the various areas within electrical engineering. However, one unfortunate consequence of seniority of that seniority power infrastructure with respect to other technologies is that America's electric power infrastructure is quite old. As the electric power power industry de-regulates and experiences increasing levels of of competition, electric utilities utilities find themselves under growing pressure to improve their bottom line financial performance as well as customer service quality. power systems whose basic design quality. Yet they must struggle with power was drafted more than a half-century half-century ago, and that are composed equipment composed of of equipment that is often up to 60 years old. infrastructures present a dilemma Aging power delivery delivery infrastructures dilemma for electric electric utilities, the electric power power industry, industry, and government. In order for our society to have electric service that is both high in quality quality and low in price, it must have both good electric systems systems and healthy electric companies. However, many of of these electric companies are in an unenviable unenviable position. Modernizing their aging systems their systems would require so much expense that they risk destroying their company's viability. company's financial financial health and market viability. Only by innovating, innovating, by taking a new approach approach and changing the way they plan, engineer, engineer, operate, particular, manage their systems, can utilities get operate, and in particular, both the system and financial performance they need. Aging Power Delivery Delivery Infrastructures discusses both the problems Infrastructures problems electric utilities face and the modern solutions that they can apply to improve their systems and customer service while keeping their financial performance at competitive levels. As both a co-author of of this book and the editor of of the Marcel Dekker Power

Copyright © 2001 by Taylor & Francis Group, LLC

ill

iv

Series Introduction

Engineering Delivery Infrastructures Engineering Series, I am proud to include Aging Power Delivery Infrastructures Marcel Dekker's Power in this important series of of books. Marcel Power Engineering Series Series books covering the entire field of of power engineering, in all of of its includes books specialties and sub-genres, sub-genres, all aimed at providing a comprehensive reference library of of the knowledge needed to meet meet the electric industry's challenges in the 21 st century. 21st Like all the books in in Marcel Dekker's Dekker's Power Power Engineering Engineering Series, this one focuses on providing modern power power technology in a context of of proven, practical well as for self-study application, and it should be useful as a reference book as well and classroom classroom use. Unlike Unlike most books, however, this is non-technical, non-technical, aimed at power engineers who need a quick, the non-engineer, as well as at those power quick, simple overview of industry. of de-regulation and how it impacts their role in the industry.

H. Lee Willis mills

Copyright © 2001 by Taylor & Francis Group, LLC

Preface This book is both a reference book and a tutorial tutorial guide on aging power delivery systems and the planning, planning, engineering, engineering, operations, and management approaches approaches that electric utilities can take to best handle the formidable formidable challenges challenges they face in working with an aging electric electric power delivery infrastructure. infrastructure. Electric power is almost unique among major public industries in one important respect: the quality and usability of of its product product is completely determined by the characteristics of of the system that delivers it, not the way in which it is manufactured. America's America's aging power delivery systems mean poor power quality, frequent and lengthy outages, and frustrating challenges for the customers, the owners and the employees of of electric utilities. utilities. They also mean poor financial performance for the electric utility companies themselves. themselves. Aging power delivery infrastructures degrade both customer service quality and corporate profit levels. This book exists because the authors believe strongly that in order for our society to have the economical and reliable electric service it needs to sustain sustain growth, it must have both good electric electric systems, and a healthy electric utility industry. In early 1994, it first because clear to us that the aging of of power delivery systems throughout the u.s. U.S. was an important and growing problem industry. Although the visible visible symptoms which threatened the entire power industry. caused by aging infrastructures - frequent and and lengthy interruptions interruptions of electric service and and rising repair and and maintenance costs - were largely incipient at that time, projections of of equipment age, system performance, and utility financial performance made it clear clear that the problem would grow exponentially. exponentially. By year 2000 it would be a major problem. Events certainly proved this projection to be

Copyright © 2001 by Taylor & Francis Group, LLC

vi

Preface

accurate. During the summers summers of of 1998 and 1999, 1999, aging utility systems throughout the United United States began to experience a growing level of of operating problems that led to rapidly rapidly degrading customer service and public trust in electric utilities. [n In the period 1994 through 1999, we devoted devoted considerable effort, both power delivery personally and professionally, professionally, to the problem of of aging power infrastructures and its possible solutions. solutions. We are fortunate enough to be with a company that is arguably the largest and the strongest power industry. strongest in the power ABB's resources, technology, and particularly international span gave us a particularly its international solutions that work. We used that platform from which which to study and develop solutions support and capability to research the problem, to determine what it was under the surface. We collected a host of of innovative innovative and proven techniques techniques for of combining these improvement from around the world. We developed ways of so they work together, and we tested them until we were confident we knew what worked, what didn't, didn't, and why. This book summarizes what we learned. We will freely admit that our efforts, which were both expensive and frustrating at times, were motivated in large part by the desire for the competitive advantage that comes comes from knowing how to solve an important, complicated, and poorly understood problem. However, the health and viability of the power industry industry are of of of great concern to us, for we are part of of it, too, and our futures depend on its prosperity. infrastructures What did we learn? Most importantly, importantly, aging power power delivery infrastructures involve much more than just aging equipment. equipment. As important as old equipment is, the problem is also very much the result of of the outdated outdated designs, constricted sites and rights rights of of way, outdated engineering standards and methods, and traditional operating procedures procedures being applied in a non-traditional non-traditional world. world. The greatest barrier to solving the problem is is not financial. Many of of the traditional greatest traditional planning, operating, and managerial prioritization prioritization methods still in use by electric incompatible with the ways that utility executive utilities are completely incompatible management must manage the financial performance of of their companies. viable, proven, and affordable solutions But most important, there are viable, solutions to the problem, solutions solutions that provide results. results. Those, along with a thorough discussion of of the problem itself itself, is the topic of of this book. This book is composed of three major sections based based on technical focus. The composed of first, consisting consisting of of Chapters 11 — 6, provides a series of of tutorial tutorial background discussions on topics necessary necessary to understand some of of the subtleties subtleties of of aging infrastructures and their solutions. solutions. The second second set of Chapters, 77 - 99,, looks at the various various aspects of of the problem, how they interrelate interrelate with with one another and the power system and an electric many functions within a power electric utility company. The third consists of of seven chapters that look at various various methods and technologies to solve the problem, leading guidelines for leading up to a series of of recommendations and guidelines those who wish to put together together a coherent and workable plan to deal with their

Copyright © 2001 by Taylor & Francis Group, LLC

Preface

vii

aging power delivery infrastructure challenges. challenges. The authors wish to thank their many colleagues and co-workers co-workers who have provided so much assistance and help during the time this book took to put together. In [n particular, we thank our colleagues colleagues Drs. Richard Brown and Andrew Hanson for their valuable assistance assistance and good-natured good-natured skepticism and encouragement. encouragement. We also thank our good long-time business associates associates Mike Engel of of Midwest Energy, Nick Lizanich of of Commonwealth Commonwealth Edison, and Randy of GPU, for their friendship, good humor and valuable valuable suggestions. suggestions. Bayshore of We also want to thank Rita Lazazzaro and Russell Dekker at Marcel Marcel Dekker, Dekker, Inc., for their involvement and efforts to make this book a quality work. H. Lee Willis Willis Gregory V. V. Welch Welch Gregory R. Schrieber Randall R.

Copyright © 2001 by Taylor & Francis Group, LLC

Contents Contents Series Introduction Preface Preface

Hi v

1

Aging Power Delivery Infrastructures

1

1.1 1.1

What Are Aging Power Power Delivery Infrastructures?

1

1.2

Power Power Delivery, Not Power Power T&D

3

1.3

The Business Environment Has Changed

8

1.4

Infrastructure Problems Five Factors Factors Contribute to Aging Infrastructure

11

1.5

Summary Conclusion and Summary

31

References

34

2

Power Delivery Systems Systems Power

37

2.1

Introduction

37

2.2

T&D System's System's Mission

38

2.3

T&D" The "Laws of of T&D"

40

2.4

Levels of of the T T&D &D System System

43

2.5

Distribution Equipment Equipment Utility Distribution

54

2.6

T&D Costs

60

IX

Copyright © 2001 by Taylor & Francis Group, LLC

x

Contents

2.7

Types of of Delivery System Design Design

70

2.8

Conclusion

82

References References

86

3

Customer Demand Demand for Power and Reliability of Service

87

3.1

The Two Qs: Quantity Quantity and Quality of of Power

87

3.2

Consumer Need for Quantity of of Power Electric Consumer

88

3.3

Electric Consumer Consumer Need for Quality of of Power

97

3.4

Two-Q Analyses: Quantity and Qua[ity Quality of of Power Are Both Important Aspects Aspects of of Consumer Consumer Value

113

Summary Conclusion and Summary

116

References References

117

4

Power System Reliability Reliability and Reliability of Service

119

4.1

Introduction Introduction

119

4.2

Outages Cause Interruptions

121

4.3

Reliability Indices

125

4.4

Reliability and Contingency Criteria for Planning

130

4.5

Cost [s Is King

136

4.6

Analysis of Two-Q Analysis of Power Systems Systems

140

4.7

Conclusion and Summary Summary Conclusion

142

References References

143

5

Economic Evaluation Cost and Economic

145

5.1

Introduction

145

5.2

Costs

146

5.3

Time Value of of Money

149

5.4

Cost-Effectiveness Evaluation Decision Bases and Cost-Effectiveness

165

3.5

Copyright © 2001 by Taylor & Francis Group, LLC

Contents

xi

5.5

Budget-Constrained Budget-Constrained Planning: Planning: Marginal Benefit vs. Cost Cost Analysis

167

5.6

Conclusion

179

References References

180

6

Equipment Inspection, Testing, Testing, and Diagnostics Diagnostics

181

6.1

Introduction

181

6.2

Inspection, Testing, Testing, and Diagnostic Evaluation Evaluation

182

6.3

Equipment Testing Testing and Diagnosis Methods Methods

189

6.4

Tests and Diagnosis of of Insulating Oil Tests

198

6.5

Summary and Final Comments Comments

206

References

206

7

Aging Equipment and Its Its Impacts

209

7.1 7.1

Introduction Introduction

209

7.2

Equipment Aging

210

7.3

Equipment Failure Failure Rate Increases with Age

225

7.4

Impact of of Escalating Failure Failure Rates: What Do Aging Utility Equipment Bases Really Look Like?

232

Summary of Key Points

238

For Further Reading

239

8

Obsolete System Structures

241

8.1 8.1

Introduction

241

8.2

Obsolete System Layouts Obsolete

242

8.3 8.3

on Operating Characteristics at at the the Sub-transmission -Impacts on

7.5

Substation Level

249

8.4

Feeder System Impacts

254

8.5 8.5

The Concept Concept of Feeder System "Strength"

262

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xii

Contents

8.6

"Fixes" for Outdated System Structures

268

8.7

of Key Points Points Summary of

271

References

272

9

Traditional Reliability Reliability Engineering Tools and Their Limitations Limitations 273

9.1

Introduction Introduction

273

9.2

Contingency-Based Planning Planning Methods

274

9.3

Limitations ofN-1 Limitations of N-l Methodology

280

9.4

Other Planning Related Concerns Concerns

293

9.5

The Problem Is Not High Utilization Rates

302

9.6

Conclusion Summary and Conclusion

303

References

306

10

Primary Distribution Planning and Engineering Engineering Interactions Interactions

309

10.1

Introduction Introduction

309

10.2

of Distribution Distribution Planning Planning and the Perceived Role of Distribution

310

10.3

Flexibility and Effectiveness Feeder Level Planning Effectiveness in Feeder

320

10.4

Conclusion Conclusion

333

References

334

11

Equipment Condition Condition Assessment

337

111.1 1.1

Introduction

337

I 1.2 11.2

Power Transformers

338

1.3 111.3

Switchgear and Circuit Circuit Breakers Breakers

345

11.4 1 1.4

Underground Underground Equipment Equipmentand Cables

348

11.5

Overhead Lines Lines and Associated Overhead Associated Equipment Equipment

352

11.6

Service Transformers and Service Circuits

357

11.7

Evaluating Evaluating and Prioritizing Equipment Equipment Condition Condition

358

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Contents

xiii

11.8

Summary Summary and Final Comments Comments

368

References References

369

12

Prioritization Methods for O&M

371

12.1

Introduction

371

12.2

Overview of of Reliability-Centered Maintenance

372

12.3

Basic Reliability-Centered Prioritization

376

12.4

Prioritization of of the Type Type of of Maintenance

388

12.5

Practical Practical Aspects for Implementation

396

12.6

Extending Reliability-Centered Prioritization Prioritization to Other Other

Operations Projects Projects

404

Conclusion and Recommendations Recommendations

410

References

412

13

Planning Methods Methods for Aging T&D Infrastructures

415

13.1

Introduction

415

13.2

Planning: Finding the Best Planning: Best Alternative

416

13.3

Shortand Long-Range Long-Range Planning Short-and

425

13.4

The T&D Planning Process

435

13.5

The Systems Approach Approach

454

13.6

Summary of T&0 Infrastructures of Planning for Aging T&D

458

References References

459

14

Reliability Can Be Planned and Engineered

461

14. 14.1I

Introduction

461

14.2

Reliability Can Be Engineered Engineered

463

14.3

Methods for Distribution System Assessment Methods System Reliability Assessment

468

12.7

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xiv 14.4

Contents Application of of Analytical Simulation Simulation for Detailed Reliability Assessment Assessment

14.5

14.6

15

472

Use Use of a Hybrid Analytical Analytical Simulation Simulation -~ Monte Carlo Method to Analyze Financial Risk

478

Conclusion and Key Points Conclusion

486

References References and Further Reading

488

Strategy, Strategy, Management Management and Decision-Making

15. Introduction 15.1J Introduction 15.2

Business Perspective Perspective on the Problem The Business

15.3

Recommended Recommended Managerial Approach: Approach: Business-Case Business-Case Based, Results-Driven Management

499

15.4

Aging Equipment Equipment and Systems -~ A Business Perspective and Systems Perspective

509

15.5

Conclusion Conclusion and Summary

518

References

520

16

Recommendations Guidelines and Recommendations

521

16.1

Introduction Introduction

521

16.2

Five Interrelated Interrelated Factors

521

16.3

Results-Driven Results-Driven Management

524

16.4

Solution Actions Recommended Solution

527

16.5

Conclusion and Summary Conclusion

543

References

543

Index

Copyright © 2001 by Taylor & Francis Group, LLC

545

1 1 Aging Power Delivery Infrastructures 1.1 1.1 WHAT ARE AGING POWER POWER DELIVERY DELIVERY INFRASTRUCTURES? INFRASTRUCTURES?

Many electric distribution utilities in the United States, Europe, and other countries countries around the world are experiencing problems in meeting their customer service quality targets, and in achieving the stockholder stockholder profit margin or government government cost-control cost-control obligations obligations they must meet. These problems are due to the fact that large portions of of their systems consist of of aging infrastructures. A power system composed of of mostly old equipment near the end of of its lifetime, itself quite old and not completely compatible with configured in a layout that is itself modern needs, produces reliability, maintenance, and budgeting challenges. If If modem these challenges are not anticipated and brought under control, they will eventually overwhelm even the most effective effective organization. organization. As this chapter will discuss and the remainder of of this book will show, aging of power delivery infrastructures involve the complicated interaction of of a host of managerial, operating, engineering, engineering, and design factors, some of of which are subtle and obtuse in their impact. Due to this multi-faceted complexity, there is no completely satisfactory simple definition of of this problem, one that will cover all situations. Some situations are unusual, a few even unique. But for the vast power delivery infrastructure" majority of of electric utilities, an "aging power infrastructure" can be described most simply as follows: follows: An aging power power delivery delivery infrastructure infrastructure is any area of of the utility system with an average service age greater greater than the design lifetime of of the equipment from which it is built.

Copyright © 2001 by Taylor & Francis Group, LLC

Chapter 1 It's Not Just About About Old Equipment

This definition is not completely representative in one very important respect. It identifies equipment age as the active factor of of aging systems and implying that it is the reason utilities have so many problems in older areas of of the system. While equipment aging is an important factor, it is not the sole, and in many cases not even the primary factor at work in creating the service and cost problems that many utilities face. Three other major factors are involved. In all cases these other three are part of of the problem and in some cases they are more important than the aging equipment. equipment. Still, overall equipment age, or "age "age of of the system," is the simplest, most effective effective way to both characterize aging infrastructures and identify identifY parts of of a utility system that suffer suffer from those problems. Characteristics Characteristics of an Aging Infrastructure Infrastructure Area

of the Situations vary, but most aging infrastructure problem areas have most of same characteristics, which are: •

The The area was was originally developed, or last experienced a rebuilding boom, prior to the 1970s. Most of of the existing system structure structure (substation sites, rights of of way) dates from before that time.



is more than forty years old. The majority of equipment in the area is



The The system is is well well engineered and and planned, in in the the sense that a good good deal of of concern concern and attention has been devoted to it. It fully meets the utility's minimum minimum engineering criteria.



The area is is seeing steady but perhaps slow growth in in load. It may may be The undergoing, or about to undergo a rebuilding boom.



The area is is plagued by by above-average equipment failure rates. rates. The Overtime is high due to large amounts of of unscheduled repair and restoration.



few years. years. SAIFI degradation leads SAIDI degradation by a few Although invariably both the frequency and the duration of of customer of customer service interruptions increase. Typically, frequency of interruption begins begins rising from five to eight years prior to big increases in SAIDI.



as a widespread interruption of service service When a major "event" such as to customers customers occurs, it is due to a series of events that are quite unusual; or something truly bizarre. These can result in the failure of of a relaylbreaker. relay/breaker. This normally would have caused only a minor

Copyright © 2001 by Taylor & Francis Group, LLC

Aging Power Delivery Infrastructures

3

inconvenience, except that it failed during the brief brief time when the system was configured into a non-standard configuration in order to support the the outage of some other unit of equipment - a contingency-switched mode where there was no backup. •

Things go go bad bad aa lot. lot.

1.2 POWER POWER DELIVERY, NOT POWER T&D

term "Power Delivery" rather than The authors have deliberately used the tenn "T &D" throughout this book in order to make a point that is both crucial to "T&D" success in dealing with aging infrastructures, but very often overlooked. The of infrastructure involved in the issues being discussed here includes a good deal of T&D of it. In order to understand the problem, and the T &D system, but not all of appreciate how to solve it effectively, but at the lowest possible cost, a person must appreciate that both problems and solutions must be examined from the standpoint of function - what does the do? the equipment involved do? Modern T&D Modem power T &D systems can be divided into two parts, or levels, based on the function of that part of of the power system under a de-regulated de-regulated structure. In terms tenns of the new de-regulated industry paradigm these are most easily distinguished as the wholesale level and the retail level. The point of of this and the focus of this entire book, is that the problems of of aging section, and focus of infrastructure, as they impact reliability of of customer service, are almost infrastructure, exclusively limited to the retaillevel. retail level. exclusively This is not to say that the wholesale power transmission level is unimportant. It is absolutely critical, and problems at that level can cause customer service interruptions. What is most important at that level, however, is system security, the continued ability of the system to remain "up and running." That is slightly different than reliability. different difference. But frankly, the consumer does not care or even recognize the difference. Whether his lights are out because the wholesale grid cannot supply all the power needed regionally, or because a part ofthe of the local power delivery chain has power failed and power cannot be moved to his his site, the result is the same - he is without electric power. But this book is about understanding and fixing the problems caused by aging power delivery infrastructures, and eradicating the customer service quality problems they cause. In that context, the distinctions between wholesale and retail matters a great deal. The record shows that the &D infrastructures are limited almost exclusively to problems caused by aging T T&D the retail level. The vast majority of customer service quality issues seen throughout the industry are created at this level, and the solution to those problems lies there as well. Problems at the wholesale level are generation shortages and an and transmission congestion congestion - very serious indeed, but that is is an entirely different different set of of concerns, and not involved with aging infrastructures.

Copyright © 2001 by Taylor & Francis Group, LLC

Chapter 1 The Wholesale Wholesale Grid

At the the generation - is is the the top top - closest to to the the high voltage grid. This is is often called the wholesale grid or the bulk power system. These names are particularly apt here, because they distinguish distinguish that part of of the utility system from the power delivery functions associated with the the customers - the the retail level. The high voltage grid exists to: I. Interconnect all generation to create a single regional system. 1. 2. Provide economic dispatch capability for the system (traditional view), or open market access for every generator (de-regulated viewpoint). 3. Provide bulk power transmission capability throughout and across the region (from boundary to boundary). 4. Provide system security - the ability to tolerate the the transient loss of any generator generator or unit of of equipment while still maintaining a fully synchronized interconnection of of the system and full capability to meet the needs for bulk transmission between regions.

of this book, the authors' will use the term Throughout the remainder of "wholesale grid" for this part of of the system. It is a critical element of of the power "wholesale industry, and to some people and from some perspectives, more important than the remainder. However, the wholesale grid is not connected to any energy consumers of of electric power, many consumers (except the few, large, wholesale consumers of of whom are also merchant generators). Failures or other problems on the wholesale grid level do not cause poor electrical service at the retail level, whether that be defined as unacceptable voltage, high harmonic content, or lack of availability. 1I of The distinction between the power delivery system and the wholesale grid is one of of function and exclusivity of of purpose. While the wholesale grid is involved in getting power to the consumer, it exists mainly or at least in large part for other reasons (see list above). Furthermore, anyone any one part of of it mayor may or may not be involved in delivering power to a particular consumer at anyone any one moment. of supply that the electric This is due only to decisions with regard to economy of Distribution Company or its customer energy service companies have made.

1

attention is is being given to the wholesale wholesale transmission transmission level, and with A good deal of attention good reason. It has its own set of of serious problems. Among them are how to maintain levels are high, interconnected security under open access when demand levels high, and how to manage and alleviate alleviate congestion problems problems on the grid caused by highly localized of these cases, but not demand-supply mismatches. mismatches. Aging equipment equipment is an issue in some of in most, nor is it in any situation the key factor of authors' opinion. of concern, in the authors' I

Copyright © 2001 by Taylor & Francis Group, LLC

Aging Power Delivery Infrastructures

Steam Generating Plant 625 MW (enough for 200,000 homes)

Hydro Electric Plant 385 MWx

Wholesale Wholesale V Power Power

Grid

V Power ' Delivery Delivery

to other neighborhoods

(Retail) (Retail)

J

Figure Figure 1.1 1.1 The electric power industry, industry, including generation (now (now de-regulated), the high-voltage transmission network (the (the open-access wholesale grid), and the power delivery level, which consists of of sub-transmission, substations, feeders and laterals, and the utilization utilization voltage system leading to all customers. customers.

Copyright © 2001 by Taylor & Francis Group, LLC

6

Chapter 1

The power Mrs. Rose uses to heat her home this week might come from parts of of the wholesale grid north of of her town, because the utility/service provider found a bargain with respect to generation located there. Next week it might flow in of flow at the wholesale level from the west, for similar reasons. This flexibility of is not just considered "business "business as usual," it is in fact a key design goal of of the wholesale grid (see number 2 in list above) and one important aspect that distinguishes it from the retail level. Factors, inefficiencies, inefficiencies, and outright failures at the wholesale level most often often affect affect market demand and supply economics transmission congestion, not customer reliability. These are price, not and transmission reliability, issues. Power Delivery: Getting Power to the People

By contrast to the wholesale level, retail, or power delivery, system exists solely solely to route power to consumers. It provides none of of the functions, even in small part, listed above for the wholesale grid, but exists only because power must be routed to consumers if if they are to buy it. Furthermore, and most importantly to this discussion, any particular consumer's power always flows through the same part of of the delivery system, except on those rare occasions when there is a contingency. The power that Mrs. Rose uses each day is intended to always always come through the same set of service drops, through the same service transformer, lateral branch, feeder trunk, substation switchgear, substation transformer, high-side switchgear, and substation transmission-level feed line. Only during an equipment failure will an alternate route be used for some part of of this supply chain. During that time the utility may be willing to accept considerably higher than normal loads and lower-than-ideal power quality in order to maintain service. "Power delivery infrastructures," aged or not, are therefore those portions of of the power system whose purpose is to deliver power to energy consumers. They are justified of the need to perform that function. solely on the basis of

Power delivery is accomplished by an "infrastructure" "infrastructure" that includes the power distribution system and a portion of traditionally was called the of what traditionally transmission system. That portion of of the transmission-level system is what was traditionally called the the "sub-transmission "sub-transmission lines - those lines that delivery power to distribution substations. substations. Figure 1.1 indicates the portion of of the power system identified power delivery system. This is normally the portion that falls identified as the power under FERC's distinction of of distribution, distribution, as opposed to transmission (Table 1.2). From the perspective used throughout this book, the wholesale grid is part of of the supply (generation system). Operating problems at that level can be serious and can potentially lead to widespread customer customer interruptions. interruptions. In a few cases aging equipment and infrastructures may be a contributing factor.

Copyright © 2001 by Taylor & Francis Group, LLC

Aging Power Delivery Infrastructures

Table 1.1 Major System Outages Outages Identified Identified By US DOE in 1999 Area

When

New England

Jun 7-8

Wholesale generation shortage shortage

Chicago

Aug 12 Aug

Multiple power delivery failures failures

x

x

30 Multiple power delivery failures

x

x

Jul

Interruption Cause

Power Delivery? Aging Infra?

New York

Ju16-7 Jul 6-7

Multiple power delivery failures

x

x

Long Island Island

Ju13-8 Jul 3-8

Power delivery delivery and grid problems

x

x

Mid Atlantic

July 6-19 Wholesale generation & & grid problems x

N. New Jersey

failures Jul 5 - 8 Multiple power delivery failures Jul5

So. Central US

Jul23 Jul 23

Wholesale generation shortages shortages

Delmarva

Jul6 Jul 6

Wholesale grid and generation shortages

x

Table 1.2 Seven Characteristics of of Distribution Delivery) Systems as Distribution (Power Delivery) Opposed Opposed to Wholesale Transmission, according to the FERC •

Local distribution distribution is is normally normally in in close proximity to retail customers. customers.



distribution system is is primarily primarily radial radial in in character. character. Local distribution



flows into into local local distribution. distribution. It rarely, rarely, if ever, flows out. Power flows flows out.



on the the local distribution distribution system is is not not re-consigned or Power on transported to another market.



on the the local distribution distribution system is is consumed in in a comparatively Power on restricted geographic area.



the interface from transmission to distribution distribution measure the Meters at the distribution system. flow onto the distribution



distribution is is of reduced voltage compared to the the transmission Local distribution grid.

Copyright © 2001 by Taylor & Francis Group, LLC

x x

Chapter 1

However, the record shows that the customer customer service interruptions and system events which brought aging infrastructures to the attention of of the industry were all power delivery related, not wholesale grid, related. Table 1.1 lists several of of the major customer interruption events in 1999. Of Of eight major events, five were involved and stayed limited to problems with the power system level below the high voltage grid. All five were power delivery system and aging infrastructure issues. Aging (of (of generation) was mentioned by DOE contributing factor in one wholesale grid event, and was cited as a possible possible as a contributing often concern in one other. However, factors at the wholesale level most often include market demand, supply economics and transmission constraints due to congestion of of poor reservation of of firm capacity by users. Beyond those major events shown in Table 1.1, there were several dozen other events of less significant impact (in terms of total customers out of of service, public recognition, and/or time involved) throughout the summer of of 1999. A number of of utilities experienced experienced continuing problems with large numbers of of small outages, which cumulatively caused high levels of cumulative customercustomerhours out of of service. All of of these problems involved only the power delivery level, and a majority was related to aging infrastructures. CHANGED 1.3 THE BUSINESS ENVIRONMENT HAS CHANGED If this were not enough, the technical, social and political environment in which If utilities must function has changed changed dramatically in the last fifty years. Actually, different from fifty years ago. ago. the environment thirty years ago was not radically different Certainly the world is a far different place than it was when the paradigm for system planning and design was developed. In 1970 most practicing engineers still used slide rules or mechanical calculators for their "desk "desk top" calculations. The electronic calculator was still in its infancy; desktop computers were not yet widely deployed. Large intensive tasks such as power system simulations were run on computationally intensive Similarly, mainframe computers from input provided by trays of of punched cards. Similarly, at home most consumers did not have any appliances or other products that relied heavily on electronics other than perhaps their radio, television or stereo system. component technology technology The transistor had been invented in 1947. Discrete component of the found its way into consumer products in the 1960s with the introduction of "Transistor "Transistor Radio". However, the proliferation of of electronics in consumer consumer massmarket products did not begin to occur on a large scale until the development of of the integrated circuit. Intel introduced the 8008™ 8008™ microprocessor microprocessor in 1972. The capability to support computational computational complexity complexity and the sensitivity of of products products to capability disturbances on the electric power supply system have been increasing at accelerating rates ever since. Today one can find integrated circuit technology

Copyright © 2001 by Taylor & Francis Group, LLC

Aging Power Delivery Infrastructures throughout the home. Televisions, clock radios, home video game systems, desk top computers, programmable microwaves, programmable ovens, programmable dish washing machines, programmable VCRs and an increasing number of of other appliances incorporating programmable controllers are becoming common place. Office Office technology has seen a similar evolution to greater greater complexity and sensitivity. Mechanical adding machines and calculators were replaced with first electronic calculators and more recently desktop computers. Mechanical typewriters were replaced with electric models, then the stand-alone word processor. Now word processing programs run on the same desktop computers spreadsheet analysis and computationally intensive used for accounting, spreadsheet engineering calculations or graphic design. Many businesses own or lease their own telephone switching systems, another application of of microprocessor technology. Likewise, production and manufacturing facilities have evolved. Manual control of of machinery gave way to analog controls. Analog controls have given way to numerical control, first to punched tape, then to process control computers. Electronics have made possible variable-speed AC motor drives. Efforts to increase productivity and efficiency Efforts efficiency in the factory have introduced many of of the same systems used in the modem modern office office to the factory, factory, such as Additionally, the desktop computers and customer owned telephone systems. Additionally, internal power distribution systems of of the plants have become more demanding Today's as they provided faster protection of valuable equipment. Today's microprocessor controlled relays, motor control systems, and recording and monitoring systems are much more sensitive than the electromechanical relays, analog instrumentation and motor control centers of of 50 years ago. While the microprocessor revolution was taking place in homes, offices and factories, little was changing in the construction of of the power delivery system. Granted, solid-state relays were developed and deployed, improving the security of of the bulk power system. The computer revolution also improved the ability of of the utility engineer to model and analyze the operation of of the power delivery system further optimiZing optimizing technical aspects of of system design in accord with the planning and design parameters developed in the 50s and 60s. Advances in measurement technology based on the microprocessor microprocessor also allow technicians to monitor the operation of the system in near real time. Digital event recorders capture the transient operation of of the system for later analysis. With the right instruments and communication channels, one can monitor various attributes of of electric service for many points on the power delivery system. itself has not changed in any significant way. Although However, the system itself there have been improvements in the quality of of the material and equipment, the system itself itself remains essentially the same. The power delivery system is composed of poles, wires, insulated cables, switches, fuses and transformers. It is subject to damage inflicted by man and nature in addition to the random and rather infrequent failure of of the components. Finally, the way in which the Copyright © 2001 by Taylor & Francis Group, LLC

10

Chapter 1

system reacts when subjected subjected to a tree limb falling on an overhead wire or a back hoe digging into a cable is the same today as it was 50 years ago. A fuse or a breaker or other protective device opens to isolate the damaged segment of the system. In the time required for the protective equipment to operate, high fault currents flow depressing depressing the voltage for all upstream upstream customers and customers on other circuits served from the same source until the protective device operates. In many systems, fast acting reclosers or circuit breaker relay schemes open and reclose before the protective device can operate in an attempt to clear temporary faults subjecting temporary subjecting all customers on the affected affected circuit to a series of of momentary interruptions. The end result of of the mismatch between the sensitivity of the equipment used by customers customers and the operation of of the delivery system has been a steady decline of the customer's perception of system performance. performance. Residential Residential customers may of system of the electronic clocks blinking or with the words arrive home and find all of "power failure" failure" showing on the display. The initiating event may have been a momentary interruption due to a tree branch brushing against an overhead conductor, or even a voltage sag due to a short circuit another circuit conductor, circuit on another circuit from the same substation. Fifty years ago with electric clocks driven by small motors, the event would have gone unnoticed by anyone not at home. For those at home, the most they would have noted was a blink or a momentary dimming of of the lights. In the office office and the factory the situation is similar. similar. In the 1980s it was not unusual to encounter problems associated associated with the application of of new utility. In one technology that was internal to the facility and blamed on the utility. instance a manufacturer manufacturer had installed microprocessor-controlled robots on an installed microprocessor-controlled arc-welding line. The controls were supplied from the same circuit in the plant that supplied the welders. It was relatively easy to demonstrate to the manager that the controls worked fine when the welders did not strike an arc. In another instance instance a plastics injection molding plant replaced replaced all of the electromechanical electromechanical voltage and current protection devices with new solid state devices. Because he was now able to do so, the plant electrician had set them at maximum sensitivity and zero time delay. The end result was that they would trip the supply to the switching operation operation on the supply line, compressor motors any time there was a switching despite being only several hundred yards from the substation. The problem was resolved by reducing the sensitivity of the protective devices to the same level of of those they replaced. replaced. Today's problems problems are not as easy to solve. Sensitive process control equipment may be built into the system that it is controlling. Manufacturers of of some products can not tolerate even a momentary interruption due to the high degree of of process integration. Sensitivity of of equipment throughout a plant may intolerable. A single momentary momentary or be such that even routine voltage sags are intolerable. voltage sag may cause the loss of of hundreds of of thousands of of dollars. Solutions to these problems have been available at utilization voltages for some time. There

Copyright © 2001 by Taylor & Francis Group, LLC

11

Aging Power Delivery Infrastructures

are un-interruptable power supplies (UPS), motor generator generator sets and constant voltage transformers to name just a few. few. Yet, it may be that there is not enough space available for the manufacturer to install the necessary mitigation mitigation equipment. Installation of of low voltage mitigation equipment at multiple locations throughout the plant may not be cost effective. effective. It is in this context that the aging power delivery infrastructure infrastructure must be viewed. Not only does the performance suffer, but also the customers have become much less tolerant of of any disturbance on the power system. Taken together, the poorer performance during a period of rising customer expectations has put the power delivery companies in the spotlight. 1.4 FOUR FACTORS CONTRIBUTE CONTRIBUTE TO AGING INFRASTRUCTURE PROBLEMS PROBLEMS INFRASTRUCTURE

Throughout the United States, and in many other places around the world, utility systems have become aged: in the sense as described portions of of electric utility above. The average age of equipment in the region or area of of the system exceeds the design lifetime for electrical equipment. Figure 1.2 1.2 shows the distribution of of average ages of of substation power transformers throughout the power industry, estimated by the authors. The mean is about 31 years, meaning that the average transformer is roughly % of of the way through its normal lifetime. The figure indicates that more than a few transformers have been in service over 60 years.

10 1001

c 75 co

~

~

s 50 so (5 c 0

t:0

IL o.

25

0

0

25

50

75

Age --Years Years

Figure 1.2 Estimated distribution distribution of of age for distribution distribution substation power transformers in the United States. Virtually none are over 75 years in service. About 25% are over 47 years in service and 50% over 35 years of of age.

Copyright © 2001 by Taylor & Francis Group, LLC

12

Chapter 1

The fact that a trans fonner, circuit breaker, or other piece of transformer, of electrical equipment is old does not mean that can no longer do its job. Old equipment will often still function, function, and although not as efficiently efficiently as modem modern units, nonetheless nonetheless get the job job done. But what age does mean is that the unit is much more likely to fail in the next year, as compared to a new unit of of similar size and design. As a of result, a system composed of of old equipment has a much higher incidence of equipment failures. failures. Equipment failures failures often lead to interruptions of of service to customers, and and that means the system provides relatively poor service - at least poor service as compared to a system that is composed of of newer equipment. This perspective provides the easiest way to define and identity identify an aging the age power delivery infrastructure infrastructure - simply look at the age of its its equipment. However, it provides only a partially view of of the problem. It is correct correct in that that equipment equipment failures do cause customer service interruptions, and that a disproportionately high number of of these interruptions are due to the failure of of older equipment. But what this perspective misses, is that three other factors common to older parts of of the utility infrastructure heavily interact with equipment age to exacerbate its effects and contribute to the overall problems of of poor customer reliability reliability and high operating costs. Essentially, Essentially, the customer customer service quality problems created by aging power infrastructures are due to, and four factors, only the solutions they must address; the combined interaction of of four one of Table 1.3 of which is associated with equipment. equipment. 1.3 summarizes these

Table 1.3 Four Contributing Infrastructure Problems Problems Contributing Factors to Aging Infrastructure

Factor Factor

of Problem % of

Description

Aging power equipment

20% - 40%

Older equipment has higher failure rates, leading to higher higher customer interruption rates. It creates higher inspection maintenance costs and much more unexpected O&M costs much more due to repair and restoration work it creates. creates.

Obsolete system system layouts

25% - 50%

Older areas of of the system system often are in bad need of of additional sites and rights of way that cannot be room for substation sites rights of obtained, and must make make do" with only that obtained obtained decades ago

Outdated engineering engineering

12% - 25%

Traditional tools for power delivery planning and correcting engineering are ineffective ineffective in recognizing recognizing and correcting some of problems that result for use of of the problems of aged equipment, equipment, obsolete system layouts, and modern modem de-regulated de-regulated loading loading levels.

5% - 50%

Planning, engineering, engineering, and operation operation of of systems using concepts and procedures procedures that worked fine in the vertically exacerbates problems when when applied applied integrated industry that exacerbates under de-regulation.

Old cultural value value

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Aging Power Delivery Infrastructures

13

four interrelated, contributing factors, which are all at work in an aging power delivery infrastructure. infrastructure. Together, they work against efficient, reliable operation of the older power system. These are discussed in more detail below, and in much greater detail elsewhere in this book.

Factor 1: Aging Equipment Contributing Factor As cited above, old equipment is a serious contributing factor to poor reliability and high costs in many utility systems. In fact, there is usually some area in any electric distribution utility's system where old equipment is a worrisome factor in providing good customer service quality. All power system equipment will eventually fail. At some point, after a period of of service, something will wear out or deteriorate to the point that it no longer adequately performs its role. The equipment will cease to provide of electrical power delivery to those customers downstream of of it. The nature of electrical equipment is that very often failures lead to a fault, requiring of the system than just protective equipment action that isolate a larger portion of the customers served by that failed unit. Regardless, electrical equipment does not have a uniform probability of of after many years of of failure with age. Usually electrical equipment fails only after completely satisfactory service. Thus, old equipment is much more likely to fail than new equipment (roughly three to ten times as likely). As a result, a system or area of of a system composed of of old equipment will have a much higher failure rate than one composed of of new equipment. This has three consequences, all of of which are undesirable: la. Equipment failure causes lower customer service quality. Customers lao Equipmentfailure of their electrical service due to are more likely to have interruptions of of this older equipment. The frequency of of the unexpected failures of interruption rises - SAIFI increases.2 1Ib. h. Higher repair and restoration efforts. efforts. More failures mean more and more unpredicted events requiring emergency emergency or contingency contingency mitigation efforts. The impact of of this on all but the most efficiently efficiently managed and staffed staffed organizations is to increase duration of of equipment outages (and hence customer interruptions). There are more numerous outages to repair, taxing the restoration and repair resources to the limit and often requiring repair of of one to wait on another. SAIDI increases slightly as a result. Also quite important for the utility's bottom line, these higher repair and restoration costs increase costs.

2 2

SAIFI, SAIFI, System Average Interruption Interruption Frequency Index, the average number of of For a discussion of interruptions of of service experienced experienced annually per customer. For of this and other reliability-related indices, see Chapter Chapter 4..4

Copyright © 2001 by Taylor & Francis Group, LLC

14

Chapter 1 1Ic. c. More inspection and testing efforts required. Equipment more prone to fail often benefits from more frequent and comprehensive comprehensive inspection and testing, which in many cases can reveal developing problems before they cause failures. Catching trouble early allows what would have become unscheduled emergency repair work to be done in a more efficient, efficient, less costly scheduled manner. This reduces the utility's utility's costs, but the inspection and testing increases required increased costs. Compared to newer systems, costs are higher.

Chapters 6 and 7 will focus on various aspects of equipment aging, its management, and the mitigation of Usually, a utility of its effects effects in more detail. detail. Usually, afford to replace all of of its aging equipment. equipment. As a result, the solution to cannot afford this particular problem source is a combination of of partial measures that seek effects: only to reduce failure rate slightly and control its effects: a) Careful assessment and tracking of of condition, reliability of b) Good utilization of of capacity and expected reliability of equipment, c) Artful Artful management of of restoration and replacement policies, d) Design of the system for for failure - planning that assumes that things will go wrong. Chapters 10 and 11 will discuss these in more detail.

Contributing Factor 2: 2: Obsolete System Layouts Contributing Layouts This, not aging equipment per per se, is perhaps the strongest contributor to poor reliability in a majority of of aging infrastructure cases. This is often not recognized or identified as an aging issue, but the facts speak for themselves. Usually, the design of of the power system in an area of of a power system, its of how they are layout of of substations and rights of of way and the configuration of interconnected and supported by one another during contingencies, dates from the time the equipment now in service was installed, installed, or before. For example: the of the power system in many urban areas of of the U.S. U.S. The central part of "downtown power system" in most large cities is based on substation sites and rights of of way that were laid out in the 1940s through the 1960s, when the post WWII boom created a period of of sustained economic growth. These designs were executed with great skill to meet both the needs of of the moment and of load growth two or more decades into the future. reasonable amounts of But between four and six (not (not just two) two) decades have passed since these systems were first laid out and built. built. In many urban areas throughout the United States, the electric demand has doubled or tripled since the power system last had a major revision in layout. By default, these systems had their layout "locked "locked in:" As the city continued to grow, the utility found it increasingly difficult to obtain new substation sites or rights of of way in the crowded, growing difficult

Copyright © 2001 by Taylor & Francis Group, LLC

15

Aging Power Delivery Infrastructures

of downtown area. Both economic and political pressures stood in the way of expanding its existing sites or adding new ones. Adding capacity at existing sites instead accommodated load growth. The utility often had to compromise preferred configuration (switchgear type and interconnection) and/or maintainability (quick accessibility) accessibility) in order to squeeze every last MVA of MVA of capacity possible into crowded spaces. At some point, equipment additions and renewals notwithstanding, notwithstanding, the power of the existing sites and rights of of way. Every bit of of system reached the limits of room had been used, every innovative trick within design standards had been out, the utility exercised, and there was simply no more room. From thereon out, either had to find some way to get the "unattainable" addition sites, or face the only other choice left: load the existing equipment in its sites and rights of way to higher levels than it would prefer. In many cases, the rather extreme situations lead the utilities to overcome significant economic and political pressures and obtain some additional sites or of accommodation of of load growth was space. But in all cases, the major manner of by simply allowing allowing loading on existing equipment to rise above traditional limits. A certain amount of of this increase is by design, and does not necessarily have a negative impact. Since the mid 1980s, equipment utilization ratios (the (the of peak loading to equipment capability) has risen through the power ratio of industry as electric distribution utilities efficiency of of utilities sought to increase efficiency equipment usage and cut back on expenses. It was not uncommon to see an electric distribution utility raise its target utilization ratio for transformers from 83% during the last 15 15 years of of 66%, about typical for the mid-1970s, to 70 - 83% the 20th century. This increase was by design.

100 55 ~ i c

__

...... ;•;';•;• .

75 75

0 0

c

f!

I-

' ' ..... " *.*.*.*'

"

*

~~~~ SS??' •

O

at

r::::::::: ...... • .... . • ..

25

10

. .E.

E

~~~I'

•••••••••

-

Ol

5..

50

'r'f'r'f

3

Transformer Utilizat

i

IT-

0

2 ••••••••

1

3

44\

5

utility Utility

D

Suburbs

II] Central core

Figure 1.3 Substation transformer transformer utilization utilization ratios in the central core and the suburbs suburbs of five major metropolitan metropolitan areas. Dotted line shows the utility's own design guidelines. of

Copyright © 2001 by Taylor & Francis Group, LLC

16

Chapter 1

of But the increases in loading forced on aging systems due to a combination of obsolete system layouts and other factors (to be discussed below) went far beyond these limits. In the central core of of many cities in the U.S., power delivery equipment such as sub-transmission cables, substation power transformers, and primary distribution circuits are alI all loaded to their maximum rating at time of of peak demand, leaving next to nothing for contingencies or emergencies. In a few cases, loadings at peak average close 100% throughout the downtown area and exceed that at a few places. Several of of the utilities that experience serious problems during the summer of 1999 had some major delivery equipment in their central systems that was loaded to over 110% of of intention. nameplate rating during peak period, not by accident, but by intention. of evidence that this trend is widespread. Figure 1.3 There is plenty of compares 1999 utilization ratios in the central core and the suburbs of of five major metropolitan systems, all among the largest power delivery systems in the U.S. Not all urban utilities utilities follow this pattern, but a majority seems to match this profile. This is not to say that the utility's engineers preferred this higher loading level level or that management and operators were entirely comfortable with the high loadings. But it was accepted, not as an emergency situation, but as the "normal" plan for serving peak demand. complicated interaction with design High loadings: a complicated of These higher loading levels were not accepted without a good deal of preparation and often often only with changes to the system to keep it, at least all cases the authors are aware of of the ostensibly, within engineering criteria. In alI utility planning planning and engineering departments' applied intense engineering methods to make arrangements so that the system could, at least based on traditional analysis, analysis, tolerate equipment outages in spite of of the potential reliability problems such high loadings could cause. However, the full implications of of higher loadings are difficult difficult to evaluate fully with traditional power system engineering tools. As a result, some of of the potential problems of of accommodating load growth in aging system areas by using higher loading levels were not fully appreciated. (This is part of of contributing cause number 3 and will be discussed later in this chapter). While the systems in question met traditional traditional reliability criteria, the systems failed to perform to the level the criteria were supposed to assure. Configuration limitations limitations Configuration In addition, it is important to realize that the obsolete system presented the utility with challenges beyond just those caused by the higher loadings that had to result from the limited amounts of of substation and rights of of way space. The utility had to distribute distribute a growing amount of power out of of the same limited number of of substation sites. This had detrimental effects effects on the performance and

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Aging Power Delivery Infrastructures

17

reliability of of the primary feeder system. Beyond a certain point, a primary feeder system simply cannot be reinforced to deliver more power out of a of sites, without accepting a certain amount of of degradation in limited number of reliability and/or cost as a consequence of of that limitation. limitation. This is due to host of of effects related to primary feeder configuration and secondary, but important effects performance that will be discussed in Chapters 7, 8, 11, and 12. Symptoms of of the obsolete system layout

The net result of of obsolete infrastructure is that higher loading levels have three undesirable consequences: 2a. Accelerated Accelerated aging. aging. Time to failure for most electrical equipment is often to a large degree a function of of its loading. The higher of the system cause utilization rates forced on utilities in these areas of electrical equipment there, particularly cables and transformers, to "age" "age" or deteriorate faster and fail sooner. Thus, in those areas where age and failure rate is already a serious concern, the obsolete system layout forces the utility to exacerbate those problems just to get by. Over time, this tends to increase the frequency of service interruptions (i.e., SAIFI goes up).

2b. Limited Limited contingency capability. High loading levels make it very difficult difficult to provide service to all customers when a unit has failed. To begin with, a system with high utilization has "a lot of of eggs in if service to consumers is each basket." When a failure does occur, if to be maintained, maintained, a lot of of load has to be re-distributed to other, stillfunctioning equipment nearby. But those remaining nearby units are already at high loading levels, meaning they have little available capacity to pick up additional load. The result is that interruptions, when they do occur, are difficult difficult to restore, involving more load transfers, more emergency measures, and taking more time. While this does not increase the number of of consumer interruptions to any large degree, it tends to increase the average duration of of interruptions that do do occur. At some point, SAIDI increases - the the number of of accelerated aging cited interruptions has gone up (due to age and the accelerated of interruptions goes up due to this above) and now the length of reason. CAIDI (essentially their product) increases considerably. 2c. Higher delivery operating costs. The distribution systems in of this is question operate at high loading levels. One consequence of the need in places for the utility to replace existing lines with a larger conductor simply to handle the MW MW-miles of delivery burden. -miles of Regardless, such systems typically have relatively high electrical losses. In addition, voltage drops are extreme. Tap changers and often and both voltage regulators operate frequently, both fail more often Copyright © 2001 by Taylor & Francis Group, LLC

18

Chapter 1 of require more preventive maintenance. These reasons and a host of effects increase operating cost at the distribution similar secondary effects level by 10%-20%.

In Table 1.2 1.2 and the discussion above, the authors have indicated that this particular cause among the four presented here typically contributes as much or more to a utility's reliability and cost problems than any of of the other three. This is because the obsolete layout interacts so much with the other aging issues. It aging. Solutions require analysis very sensitive to the exacerbates equipment aging. weaknesses of weaknesses of traditional engineering methods. And, on its own, the obsolete system layout creates operating and reliability reliability challenges. Both the problem and its solutions are complicated because they interact so strongly with both the other three causes of of the aging infrastructure problem, and with many other aspects of of the power delivery utility's operation. Generally, the solution is some combination of: a)

Somehow obtaining a few new sites and ROW to improve the system layout,

b) Use of of innovative means of of squeezing more capacity into existing sites, and most important, c)

Optimized configuration of of substation switching and buswork, and primary feeder-level feeder-level switching, based on sound reliability-based engineering (to see discussed below).

Chapter 8 focuses on obsolete system layout and its effects in more detail.

3: Old Engineering Methods Methods Contributing Cause Number 3: Many T T&D &D utilities utilities are using engineering methods that worked well in the 1970s, but cannot fully guarantee reliability operation in a world where substation and line loadings are pushing beyond traditional levels. As a result, engineering planning functions at many utilities cannot identify identify precisely precisely what the problems are or prescribe the most effective effective and economical remedies. This particular subsection will provide a particularly comprehensive summary of of this subject. Engineering tools are in an area where utilities can make immediate improvements and one where improvement must be made if the aging infrastructure issue is to be properly addressed. Chapters 9, 12, and 13 13 provide more detail on this subject. N-1 criterion

Traditionally, reliability was designed into a power system by making certain that there was a "backup" of of sufficient sufficient capability for every major element of of the power system. If of that failure were If that element failed, negative consequences of

Copyright © 2001 by Taylor & Francis Group, LLC

Aging Power Delivery Infrastructures

19

Any one covered. This is called "N-l" planning, or use of the N-l N-l criterion. Anyone element of of the power system, composed ofN of N elements, can be removed, and the system will still perform its job, even under the most stressful stressful (peak) conditions. Simply stated, one bought reliability reliability with capacity N-l N-l engineering is done by running N separate studies of a power system, one in which each of of the N elements is removed (outaged) and the system switched as appropriate to have other equipment pick up the load it was serving. Computer programs that use a load flow algorithm (the basic power system simulator simulator which estimates voltage, current, and loading throughout a power of conditions) have been written to do this system for a specified set of automatically. The power system engineer inputs a description of of the system and its loads, and the program both solves the "normal" (everything working) load flow case and all N "single contingency" (one element out) cases, and reports all with any problems such as overloads, low voltages, poor power factor, etc. is called the the "N-X" criterion - a power More generally, this approach is of N elements can be designed to tolerate the loss of of any X elements. system of This requires N Xx cases to be run by the automatic analysis program. throughout the power industry. N-I approach is dogma throughout The use of this N-l successful: systems designed with it Developed in the 1960s, it proved very successful: worked well. Every major utility developed the design of of its high voltage transmission grid, sub-transmission and substation systems, and other critical of its system, using this method. Nearly every utility modified the elements of method in numerous small respects to fit its needs or preferences, but overall, this approach was universally applied. applied. The reasons were: so that if 1) The The basic concept makes tremendous sense - design the system so if anything goes wrong, nothing bad happens as a result. 2) Experience showed that this method worked: traditional power systems designed with this approach provided good reliability. 3) There were no alternatives, at least originally. N-1's limitations N-l approach is a sound engineering method, in fact one that the authors The N-l of any power system planning and engineering procedure. recommend as a part of But like all engineering methods it makes assumptions, uses approximations, and take short cuts to gain efficiency efficiency - in other words, it has its limits. limits. There is no doubt (based on publications from the 1960s and 1970s) that the engineers developed and first applied N-l who developed N-l recognized these limitations. However, because the traditional applications of N-l seldom encountered these of N—1 limitations, and because institutional memories are short, many utility planners and engineers working today never considered that as conditions change, their systems might run into those limitations. Copyright © 2001 by Taylor & Francis Group, LLC

20

Chapter 1

By any practical standpoint, N-l necessary requirement N-l capability is a necessary requirement for reliability. To be reliable, a power system must have the ability to power system reliability. tolerate the loss of anyone any one element of of the system and still do its job. However, necessary and sufficient sufficient criterion. One that, if that does not make it a necessary if met, assures adequate reliability of of service, which is how the industry often often has applied the criterion and methods based upon it: design a system to meet N-I N-l and it was by definition "reliable enough." The fact that a power system meets N-l criterion is not sufficient N-l sufficient to assure that it will provide satisfactory reliability, or even fairly good reliability. As proof, it is only necessary to look at the system outages that occurred in summer of of 1999. All of of the systems that experienced severe reliability problems fully met N-l N-l and many cases met N-2, and even N-3 design criteria in critical critical places. N-l 's "ragged edge" as a dependable planning tool revolves around its lack N-l's of probabilistic expectation in its computations. N-I N-l methods and the N-I N-l criteria assure power system planners and engineers that there is some feasible feasible way to back up every unit in the system, should it fail. However, they make no assessment assessment of of how likely the system is to get into situations that go beyond that. N-l N-l methods do not provide any analysis of: • How How likely is is itit that backup will be needed? needed? • How How reasonable is is the the feasible plan for for each contingency situation? situation? Is the planner is actually building a "house of of cards" by expecting "too "too many things to go right" once one thing has gone wrong?

How much stress might the the system be be under during such such • How contingency situations, and what are the long-term implications for both equipment life and operating feasibility of of the system? • How How often do do conditions occur which cannot be be backed up up (e.g., (e.g., multiple failures) and how bad could the situation become when that is the case? N-l criteria can be less reliable than needed As a result, systems that meet the N-l N-l criteria "guarantees" there is a engineers might expect, even though the N-l way to back up every unit in the system. This is much more likely to happen in modem power systems than it was in traditional, regulated power systems, due modern to changes in utilization and design made in the period 1990-2000, and the more volatile operating environment of of de-regulation. The reason is that modem modern power systems are much "leaner" than those of N-l was first developed and applied. In the thirty or forty years ago, when N-l 1960s through the early 1980s, electric utilities typically loaded key equipment, such as substation power transformers and downtown sub-transmission cables, of their capacity, even to only about 2/3 or a little more (typically about 66%) of "operating reserve" or during peak periods. The remaining capacity was kept as "operating

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Aging Power Delivery Infrastructures

21

"contingency margin." Engineers and planners at distribution distribution utilities designed their power systems using the N-l and other criteria, while counting on this N-l was both necessary and sufficient margin. In this environment, N-l sufficient to assure good reliability. utilities Beginning in the 1980s and increasingly throughout the 1990s, utilities pushed equipment utilization upwards to where, in some systems, the average substation transformer was loaded to 83% of of its rating during peak periods. As will be discussed in Chapter 8, in aging areas of of these systems, which suffered suffered from "obsolete system layout," utilization rates often averaged close to 100% under "normal" peak conditions. Whenever a power delivery utility increased its planned equipment utilization rates, changes were carefully carefully engineered into the system, so that it N-\ criteria everywhere, and even attain N-2 N-2 capability in could fully met the N-l critical places. This despite the greatly reduced contingency margin levels now available: there were feasible feasible ways to back up any and all failures, despite the higher utilization rates. rates. However, as will be discussed in Chapter 9, this fell far short of of providing traditional levels of reliability. reliability. N-\ N-l is not sufficient sufficient to assure traditional levels of reliability, when the system is operated at high utilization rates. Basically the of reasons are that such systems are much more likely to experience "high stress events" to the point that situations that go beyond the N-l N-\ backup capability and are far more likely to occur. Such systems may have from three to five times the potential for customer service quality problems as traditional systems. Coupled with the higher failure rates caused by aging equipment, this creates a serious service quality handicap for the utility. Other Engineering and Planning Related Problems

Power systems that operate with either an obsolete system layout and/or at high utilization rates are sensitive to more than just probability-related increases in interruption rates. The sensitivity of of the system service quality to other problems increases exponentially. In particular, problems are encountered with partial failures, configuration complexity and load forecast sensitivity, which are discussed in further detail in the following paragraphs. paragraphs. Partial failures failures

Contingency-based methods such as N-l N-\ are basically "zero-one" models of of failure: a unit of of equipment is modeled as completely in, or completely out of of service. But modem modern power systems often encounter partial failures or operating of some components: constraints of



A transformer may may be in service but its its tap tap changer has has been diagnosed as problematic and is locked in one position.

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22

Chapter 1 •

An oil-filled UG UG cable's pumps are are disabled and and the the cable has been de-rated.



bus ground that failed tests has has dictated opening a tiebreaker to A bus balance fault duties.

These and other similar problems impact an area of of the system with obsolete system layout or an area of of the system operating at high utilization ratios, far more than they impact a traditional (66% - 70% The 70% utilization) power system. The obsolete layout is stressed with respect to voltages, flows, etc., and limitations limitations in its full equipment usage due to such partial failures failures adds stress and often "uses up" contingency capability. A power transformer loaded to 85% at peak, whose tap changer is locked into one position, is subject to voltage regulation problems that can easily reduce its ability to handle load by more than 15%. The N-I method assumes is there, contingency margin (85%-100%) that the typical N-l is in fact gone. Configuration Configuration complexity complexity

At high utilization levels a system needs additional switching flexibility to accommodate its need to backup equipment operating at high loading levels with other equipment that is also already operating at high loading levels. Traditional N-1 N-lengineering engineering methods are capable of of analyzing the additional complexity this additional switching adds to the system design, at least from the standpoints of of both electrical flows and feasibility evaluation of of contingency operation. However, configuration decisions at substations (i.e., ring-bus vs. breaker-and-a-half breaker-and-a-half vs. double bus design) and feeder layout and how likely and and branching/switching design (see Chapter 10) affect affect reliability reliability - how how often - failures failures or outages will lead to interruptions. When configuration becomes more complex, as it does in most cases where adequate levels of of of reliability are being sought when utilization rates are high, the interaction of reliability is non-trivial configuration and reliability non-trivial and not intuitively obvious. Candidate plans that look like they will provide an improvement can, in fact be less reliable overall. N-1 N-l methods cannot assess, nor provide good feedback to engineers on the interaction of of configuration with actual customer-level reliability. For this engineer-planner's understanding reason they leave a gap in the engineer-planner's understanding of of the system being designed. Generally, systems laid out only with N-l N-l methods have feasible contingency capability, offer offer far configurations, which will, will, providing feasible reliable operation. less operating flexibility than really necessary for reliable

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Load Forecast Sensitivity Sensitivity A system that is under a good deal of of stress, either because it has a system layout that is less than ideal for its load levels, or because equipment is being operated operated at high utilization rates, is particularly sensitive to errors in the load forecast used in its planning. Poor load forecasts used in the planning or of a power delivery system effectively effectively "use "use up" its contingency operation of capability [Willis and Powell, 1985]. This will be discussed in more detail in normalization of of weather weather data for forecasting or poor spatial section 9.2. Poor normalization forecasting (poor correlation of of loads with areas and equipment) result in deterioration of of a systems contingency to withstand capability. This greatly deterioration exacerbates exacerbates the reliability-of-service problems discussed discussed up to this point in this chapter.

Contributing Cause 4: Non-Optimum Use of the Primary Distribution Distribution Level Averaged Averaged over the entire power industry, the primary distribution system is without a doubt both the most important and least well-used part of of the power delivery chain, for several reasons. First, it accomplishes accomplishes more of of the power of the system, in the sense that power is delivery function than any other level of routed into a few locations in fairly large chunks. Then the distribution system routes and sub-divides that power into very small allotments delivered to many different different locations. No other layer (See Figure 2.3) of of the power system accomplishes so much dispersion over area or so much sub-division of of power. Secondly, the primary distribution level has more impact on customer power quality than any other layer. In the vast majority of of power systems, it is both immediately downstream of of the lowest voltage regulation equipment (substation changers) in the system, and by the nature of of its its voltage regulators or load-tap changers) topography, the source of of the majority ofvoJtage of voltage drop from that regulation point to the customer. That topography also guarantees guarantees that the primary distribution of outages that lead to customer customer service interruptions. system sees the majority of Thus, in most systems, the distribution system is the source of of the majority of of both the voltage-related voltage-related and availability-related power quality problems seen by energy consumers.

Not well used At many power distribution utilities, the primary distribution system is planned and engineered using principles and layout concepts that were developed in the 1920s and 1930s and that have been handed down through generations of of re-examination. Foremost planners and engineers without substantial revision or re-examination. among these long-time "habits" are the overall layout style of of the primary feeder system: whether the large trunk, multi-branch of of the hierarchical subdivision, often-called often-called "feathered" "feathered" template template for radial feeder layout, guides that. Copyright © 2001 by Taylor & Francis Group, LLC

24

Chapter 1

Additional factors include switching zone and contingency backup policy, voltage regulation and 'reach" design, and conductor set selection and tapering policy. Any reasonable layout style, conductor conductor size set, switching zone, and conductor sizing rule base, will result in a distribution system that does its basic conductor job as interpreted from the traditional perspective: route power from substations job to customers without violation of voltage, loading, or power factor standards. job is obsolete, and However, this interpretation interpretation of the distribution system's job of incomplete. It looks at the distribution distribution function only from the perspective of moving power and neglects its role in and capability capability for improvement of of customer-service reliability. Very few primary distribution distribution systems are planned and engineered to make maximum use of of the distribution system as a resource for customer reliability. As mentioned above, the guiding rules for primary distribution planning and design at most utilities utilities were developed in the 1930s, and last seriously reAdditionally, they are applied in a examined and revised in the late 1960s. Additionally, "cookie cutter" manner, using rules-of-thumb, informal guidelines for the larger of layout, switch planning (along with copious formal guidelines about issues of the details), and rote rules for overall design. In a majority of of cases, these rules are often too conservative, not allowing the full use of of distribution as a resource.

untapped resource resource An untapped As a result, distribution systems in most utilities are underutilized in two ways: 1.

Economics -— when viewed just from their standpoint of of their traditional function moving and and dispersing power -they cost more than is necessary.

2.

the primary system to to Reliability - the the potential of the partially maximally contribute to improved reliability reliability is partially untapped in the vast majority of of cases.

.xx gives gives statistics statistics on on the the results results of of "distribution "distribution optimization" optimization" studies studies Table 1I.xx from six utilities, which the authors' have recently worked. These utilities are representative of all the utilities the authors have worked with over the past ten years. They are an average set, not a set picked to show particularly good of improvement that is possible by results. They demonstrate both the margin of updating and modernizing primary distribution planning and design paradigms, different utilities. and the variation that is seen among different utilities.

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Performance Derived from Table 1.4 Improvements in Distribution System System Cost and Performance Revision of of Traditional Design Guidelines and Engineering Engineering Methods

Case

Utility System System Type

1 Urban UG, UG, Atlantic Atlantic coast coast 2

Rural, small towns, Central US

3

Metropolitan, Metropolitan, Midwest US

Electrical $ Existing $ 8%

2%

System Reli. Reliability Reliability $ System 79%

3.4:1

12%

0%

25%

.8:1

6%

3%

40%

1.8:1

4

Entire system, IOU, Central US

2%

3%

36%

1.5:1

5

Rural, small towns, Southern US

12%

11%

1.6:1

6

Entire system, N.E. US

22%

16%

10%

6%

25% 33% 40%

Averages

.92:1 1.7:1

Table 104 1.4 lists four statistics for each system. The first, "Electrical "Electrical - $," is the reduction in overall (lifetime) cost of of distribution that could be wrought with respect to the traditional primary distribution paradigm of of moving power. This is the savings in new capital additions that result from improving how the do its its traditional job - moving power. to do distribution system is designed to "Existing - $" shows how much the useful utilization of of The second statistic, "Existing an existing distribution system can be improved with respect to that traditional paradigm. Existing systems encompass both the good and bad points of their past engineering and design, and those systems cannot be thrown away and redesigned based on new and improved rules. However, as shown, some improvement can be wrought in the MW/$ capability of of these systems. However, improvement is only useful where needed (i.e., if one improves a 5 MVA feeder so it can carry 504 5.4 MVA, that is useless unless it is in an area where one needs A MVA more capability). These values reflect both what is possible, and what was found useful, on the respective systems. The third statistic, "Reliability of "Reliability - $," represents the reduction in the cost of improving reliability that was attained by revising design guidelines and applying the most effective effective reliability-based planning and engineering engineering methods to these systems. These improvements while rather dramatic, are typical. As stated earlier, distribution systems are simply not designed from a reliability standpoint. When this is done and the engineering is optimized, the result is a very considerable improvement. The final statistic, "System Rel.," represents the margin in "bang for the buck" that the revised distribution reliability improvement made over the existing cost of improving reliability that was in effect effect before the revision. This statistic goes to the heart of of the use of of distribution as a resource in aging infrastructure areas, and of of the authors' overall theme of of using all of of the power system chain optimally to obtain the greatest "bang for the buck." In four of the Copyright © 2001 by Taylor & Francis Group, LLC

26

Chapter 1

six cases listed, reliability improvement was between 20% and 40% less of the system. In these expensive to buy at the primary level than at other levels of cases, spending on the distribution system could deliver reliability improvement for less cost than spending on other levels of of the system. In two other cases, this was not the case, and the value shown is negative. Of Of note here is that the utilities were unaware of of this entire issue, because the traditional tools they were using for the design of of all three levels were not of even measuring such things as capable of directly engineering reliability or of reliability improvement per dollar. dollar. Thus, in all cases, improvements of of between 9% (1/ (I/ 92 92 - see see final column) and and 70% 70% were possible by by adopting reliabilitybased engineering methods and using them at the distribution system and for coordination of of design among the distribution distribution and sub-transmission-substation levels. of distribution system guidelines and Table 1.4 makes it clear than revision of of reliability-based engineering methods should be viewed as a adoption of of the traditional (electrical) perspective on valuable improvement in terms of of 10% and 6% are very distribution. The improvements in cost effectiveness of noticeable and quite valuable. "modern perspective" - one one that However, from what might be termed a "modem of both performing the electrical duties and views the system's role as one of providing reliability of of power availability, availability, the improvement represents a quantum leap in cost effectiveness. By looking at the distribution system as a reliability resource, and optimizing its use for that purpose, an average 40% of reliability improvement is obtained at the increase in cost effectiveness of distribution level. Coordination of of that with the planning and design of of other of the system achieve a 70% increase in overall effectiveness effectiveness of of money levels of spent on reliability improvement. The authors are aware that many readers, particularly some with long experience as planners at power delivery utilities, will dispute that these improvements shown are theoretical and were not implement-able (they were), different (not likely), or that that their system is different likely), or that "it won't work here" (it will). Chapter 10 will go into more detail on these improvements.

rocket science science It js. is rocket The rather significant improvement in effectiveness that is possible by revising engineering methods at the primary distribution guidelines and adopting newer engineering level brings up a key point about why the industry clung to what are essentially outdated engineering engineering practices for so long. Distribution planning and outdated engineering at most utilities utilities is kept at a rather low level. Engineering of of a distribution system so that it performs the basic electrical functions that were traditionally required of of it is rather straightforward. It can be done and was done for decades with nothing more than rough calculations (slide

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rules at best), nomographs and tables, rote-memorized rules of of thumb, and institutionalized memory informally handed down from one generation of of engineers to another. When digital computers are used, that level of engineering becomes quite simple. For this reason, one often hears terms such as "it isn't "distribution planning and design are quite simple." This rocket science" or "distribution cultural paradigm is exacerbated by the following I) Distribution is of following facts: 1) of relatively low voltage (compared to other parts of of the power system; 2) the equipment involved is rather small and inexpensive (compared to other levels) and; 3) the system is normally laid out in radial form (which makes power flow easy to calculate). In fact, the power distribution system is by far the most difficult difficult of of all layers in the power system to plan and engineer to a truly high standard. It ~ is rocket science, because distribution systems are like piranha. Yes, all the equipment is low voltage, all of of it is small, and each unit is some type of of very common, "commodity" design. But a distribution system consists of of tens or hundreds or thousands of of thousands of of these components. In aggregate it is large, expensive, and most importantly, very complicated. A distribution system represents a tremendous and challenge in combinatorial decision-making - in deciding how how to to select and arrange equipment, line routes and capacity tapering, interconnection, normal and contingency flow patterns, and a myriad of of other factors to best achieve the required goals. It is possible to select and arrange this equipment based on standardized layout rules, traditional (and rather straightforward) guidelines on equipment and engineering methods, so that it works well enough from an electrical standpoint. Beyond this, distribution systems present a number of other challenges which of ultimately create a large gap between the quality of of a plan that works, and that of majority a really good plan. First, the distribution system has to handle the vast majority (roughly 95%) of of the load coincidence (diversity of of peak) dynamics on the system. Secondly, distribution is closer to the consumer than any other part of of the power system: it has more than its share of of constraints on routing, equipment placement, and design. Third, distribution must deal with a good deal of of 'fuzziness' in terms of of the demand levels it serves. Unlike at the transmission level, accurate load measurements are far and few between. Usually loads are estimated from metered, kWh data, and assumed values of of diversity. For all of of these reasons, getting the most value possible out of of an existing distribution system, or from new investment about to be made in it, is more difficult difficult than in any other level of of a power systems. Distribution planning, done effective manner possible, ~ is rocket science. to the most effective

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Chapter 1

Contributing Cause 5: 5: Old Cultural Identities and Ideas

Old habits die hard. At some utilities, utilities, the managers, planners, engineers and operators still tend to think in terms of of the culture and goals that were appropriate for a purely regulated, vertically integrated industry. New goals may have been articulated, but for various reasons a change in thinking, in priorities, and in method has not followed, followed, one which makes the planning, engineering, and operating compatible with those new goals. Certainly, to some extent, the use of the out-dated engineering methods cited earlier could be characterized as part of this problem. Particularly, the considerable resistance to new ideas that prevents many utilities utilities from fully adopting new reliability reliability approaches (Contributed Cause 3, above) and distribution planning practices and guidelines (Contributing Cause 4, above) is mostly due to cultural resistance to a change in institutionalized values and methods. However, the the authors have identified those as as separate issues - methodology, rather than culture -~ in order to focus attention on broader broader issues. In a number of of cases, perhaps half half of of the aging infrastructure problems the authors have analyzed - retention of outmoded priorities, corporate values, and has and concepts - has been a contributing factor in the problems the utilities experience with aging infrastructures. This is often not a result of of resisting change as much as one of of recognizing when, how and where to change. Executive Executive management's management's perspective: perspective: a more business-driven business-driven focus

Since the power industry was de-regulated in the mid 1990s, the 21 21stst century power companies and distribution utilities that fell out of of the dis-aggregation of of traditional vertically integrated integrated utilities, utilities, began taking a more "business driven" approach to their decision-making. Investments and operating policies were justified justified on the basis of of their business case: if and how much they helped the bottom line of of the business. This perspective is a huge departure from the values traditionally utilities. Executives at many modem traditionally used at many utilities. modern utilities drive all priorities into their organization starting from their financial model. "What will it take for us to achieve our financial goals?" Budgets and priorities are set by that requirement. While electric utilities always recognized they were businesses, many of of the values they used in decision-making were based based on a "public stewardship" of cost. This attitude made sense concept that does the right thing, regardless regardless of within the traditionally regulated utility business model. Any expenditure justified within that framework could be put into the rate base. Ultimately the utility would recover its expenditures and earn a reasonable return on invested capital. Deregulation, and shifts in attitudes within the industry and regulatory

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expenditures and agencies, has changed that perspective. No longer are capital expenditures operating expenses acceptable to a utility's management just because projected revenues will cover all projected future costs. Executives insist that spending be business-related reasons. Regulators are concerned contained for a variety of of business-related about price as much as quality. The result is a system that is much more focused of each project, not just the assurance that a project on the business implications of is the minimum revenue requirements solution to a given "problem," as defined by the planning guides. In this new paradigm, traditional values such as good customer customer service, high utilization of of physical assets, and efficient efficient operation operation are all-important priorities, because they contribute to that end. It is interesting that there seems to be more operation under deregulation than there focus on these "virtues" of of good utility operation was under a traditionally regulated operation. Certainly utilization rates are higher, attention paid to reliability is greater than ever, and more effort effort is being directed at improving efficiency efficiency than ever before. The reason is that when one has less of effort is put into getting of something, more attention is given and more effort the most out of of it. Modern utilities understand that all of of the virtues they desire boil down to one resource: money, and that they will never have enough to meet all possible needs based on traditional planning standards. standards. Additionally, in aging infrastructure areas, a power distribution utility will have nowhere near enough money to take the "obvious" approach to the aging infrastructure: replace all the old equipment and upgrade the obsolete layout. There simply is not enough money. This makes the whole planning situation budget-constrained. The overall, executive management budget-constrained. management perspective perspective is thus, "The distribution system is a physical asset that we purchase "The and maintain to provide good customer service and stockholder profits. It is doing its job job when it supports our business model." mode!." Changes in cultural "standards" may be needed

Many of of today's power delivery planning, engineering engineering and operating concepts were developed by or for vertically integrated integrated utilities in a regulated, noncompetitive industry. Some are quite inappropriate for a business-driven business-driven utility environment. They use procedures that are rule- rather than results-based procedures, and thus not easily adaptable to an environment, in which decisions are ultimately driven by financial, financial, rather than standards or policy, considerations. Required changes are scattered throughout throughout this book, but in general, the utility needs to re-examine:



Standards and and guidelines -- one one utility that encountered severe severe problems in 1999 had not re-examined re-examined and revised its distribution planning and engineering engineering guidelines and standards since 1978. Forgetting entirely the issues of of de-regulation and competition, load

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30

Chapter 1 characteristics, characteristics, capital vs. operating operating cost considerations, and a host of of other changes in system requirements have occurred in the intervening 28 years.



Budget base. from year-to-year by base. Many utilities utilities operate from by revising revising the current year budget incrementally for the following year. Budget allocations and functions among departments are effectively effectively institutionalized along traditional lines.



Protection and restoration practices at at many utilities utilities follow follow practices developed in the late 60s and early 70s. These are often often incompatible with modern modem consumer needs of of fewer interruptions and do not make use of modem equipment and techniques for of the most modern elimination of of interruption propagation through the network whenever an outage occurs.



Prioritization Prioritization of of projects projects is is still based on on models and and concepts concepts developed while utilities utilities were regulated, vertically integrated integrated companies. Most of of these prioritization methods are entirely incapable of of allocating a limited limited (constrained) budget among needed projects in the best possible manner [Willis, 1997, Chapter 18]. l8].



Reliability engineering engineering at at many utilities utilities is is mostly reactive. reactive. Reliability Reliability analysts review operating records and experience experience in order identified, to identifY identify poor performing areas or equipment. Once identified, these areas are turned over to Engineering and Planning for rehabilitation, using what are basically traditional traditional contingency-based contingency-based tools.



System design at at many utilities throughout the the United States still follows specific styles and guidelines developed decades ago. Nearly every utility in the industry has slightly different different preferences in how it lays out and specifies equipment for substations, how it routes, sizes, and switches feeders, how it designs its protection protection schemes schemes and cOontingency backup plans, and how it operates its system at times of of high stress. Every utility insists that its methods are best. But they can't all all be correct - in fact few few have it right, and all all can learn by reviewing what other utilities do best.

In these cases, and a host of of others, utilities can make improvements by reexamining what are often practices and unique characteristics often long cherished practices characteristics or policies, which they firmly believed in. This fresh approach approach should both look at practices were the changes changes in customer loads and needs since the last time practices examined, and should make certain that the new standards, guidelines, methods and practices are maximally maximally supportive of of business-driven focus of of the utility.

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Inappropriate paradigms reduce the effectiveness of of efforts the utility makes to improve or maintain performance, particularly in areas where reliability is relatively costly to maintain (aging areas). The impact is raised costs, which translates to increases in SAIFI or SAID!, SAIDI, whichever the utility needs, because money is used inefficiently, which would otherwise go to make improvements as needed. 1.5 CONCLUSION CONCLUSION AND SUMMARY SUMMARY

An aging power delivery infrastructure is an area of of an electric utility system that is composed of of mostly old equipment near the end of of its lifetime, configured in a layout that is itself quite old and not completely compatible with modern needs. Situations vary from one location to another, but most aging infrastructure areas share similar characteristics, characteristics, exhibiting a type of "signature" as listed in Table 1.5 1.5 summarizes 1.5 and discussed earlier in section 1.1. Table 1.5 eight ofthe of the most typical characteristics of of aging infrastructure areas. For a variety of reliability, of reasons, the aged equipment and layout create reliability, maintenance, and budgeting challenges that will eventually overwhelm even the most effective effective and efficient efficient utility company if if not anticipated and brought under control. The most easily identifiable characteristic of of aging delivery

Table 1.5 Characteristics Characteristics ofthe of the Typical Aging Infrastructure Area

1.

The system layout and design was first put in place more than forty years ago. ago.

2.

The majority of of equipment in the area is more than forty years old.

3.

The system is well engineered and fully meets minimum engineering criteria.

4.

The area is seeing steady, if perhaps low, load growth in load.

5.

The area is plagued by above average average equipment failure rates. Overtime is high due to large amounts of of unscheduled repair and restoration. restoration.

6.

SAIFI began began rising some years ago; SAlOl SAIDI is beginning to rise now.

7.

Major interruption events always occur due to a bizarre series of Major of outages. outages.

8.

Things go bad a lot.

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Chapter 1

32

Table 1.6 Summary of of Suggested "Fixes" for Aging Infrastructure Problems Priority

Action

Comments

1

Cross-functional Cross-functional results-centered management management

Optimizes and coordinates overall utility focus. Accommodates Accommodates other planning, engineering, operation and management methods aimed at improving reliability.

2

Zero base all budgets

re-justifY itself, itself, at least Make everything re-justify once.

3

Augment N -I -1 with with reliability-based reliability-based methods

Optimizing reliability reliability (obtaining the most for the less cost) requires using techniques that explicitly measure the expected expected reliability reliability and engineer it.

4

Use budget-constrained prioritization prioritization methods

Proven effective in allocating budgets most effectively when there is not nearly enough effectively "worthy causes." money for all "worthy

5

Apply Reliability-Centered Maintenance (RCM) It works, reducing maintenance costs and improving results.

6

Optimize planning planning & & operation against PBR

Let regulatory rules define the specific targets for customer customer service quality.

7

Revise standards & & guidelines guidelines to modern needs needs

Make equipment usage and system system design design rules compatible with themselves and with modern needs.

8

Adopt results- rather than than rule-based standards standards

Pragmatic and flexible flexible standards standards are necessary necessary if maximum results are to be obtained.

9

Use IT systems focused on customer service service

Focus "if-y" information systems on improving customer service, not reducing reducing cost.

10 Implement TLM type equipment tracking

produce of Periodic equipment equipment evaluation and produce of "jeopardy lists" can improve effectiveness and cut failure impact.

II 11 Optimize equipment equipment loading for service value

depending on the Load equipment differently depending situation

12 Use innovative innovative compact substation design

Innovative substation layouts and equipment can pack up to three times the capacity and ten times the reliability reliability into the same site size.

reliability 13 Optimize substation configuration for reliability

Reliability engineering engineering intensely applied to high and low side design design of of substations substations can greatly enhance overall customer service service quality

14 Minimize Minimize operate operate voltage at the primary level

Reduction in primary distribution distribution voltage to lowest possible level consistent the lowest consistent with good service can reduce equipment aging rates by up to 10%

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33

infrastructures is that the equipment in the area is old. It will have an average service age greater than its design lifetime. However, this chapter presented five interrelated problem areas that all contribute to the poor customer service levels seen in aging delivery infrastructure areas. Table 1.6 lists these four problem areas and specific factors within each, and describes whether they impact mostly the frequency of (SAID!) or of customer service interruptions (SAIFI) the duration (SAIDI) the costs a utility sees in trying to provide good service. What Can Be Done The conclusion of this book, Chapter 16, recommendations and 16, summarizes the recommendations guidelines developed in Chapters 2 through 15. Central to the entire approach, however, are the six "guiding principles" of of result-centered result-centered approach. 1. Use a results-focused results-focused approach. The two results desired are customer service quality and low cost. Thus, the guiding principle above all others is to maximize their ratio over the entire system. This is discussed nearly everywhere throughout this book. 2. Zero-based all decisions and budgets. Nothing is scared, and no level

of expense is considered acceptable just because they represent a of of spending in that category. traditional level of 3. Marginal Marginal benefit/cost benefit!cost ratio should be used as the basis for all of "bang for the buck." This provides far superior results evaluation of to prioritization done on the basis of of benefit/cost ratio or other means. This concept is discussed and developed in detail in Chapters 5 (section 5.3), 11, and 14. 4. Macro-comparison of of intra-project infra-project alternatives using that marginal

benefit/cost ratio should be used across departmental and functional benefit/cost functional boundaries to prioritize spending decisions among candidate projects "technical title" actually describes a and budgets. This rather lengthy, "technical rather simple but critical procedure, in which the keys to making results-centered results-centered management work, is covered in Chapters 11 and 14. 5. Reliability-based planning, engineering, operating and maintenance methods should be employed throughout the organization and a customer reliability-focused reliability-focused approach should guide all decisions on IT.

6. Planning for for failure.

The best results come from a management

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34

Chapter 1 perspective that recognizes that equipment failures failures are not the result of of an "our "our failure" and that they cannot be avoided. They can, can, however, use, be managed. Failures are a natural consequence of equipment use, and they will happen. Their likelihood and consequences can be engineering and managed.

Table 1.6 summarizes the major specific operational recommendations recommendations developed from this guiding principle, as given elsewhere in this book and summarized Chapter 16. summarized in Chapter 16. The central theme is "results-centered management," the use of management," of a combined business-engineering business-engineering prioritization focus on reduced customer service problems at a minimum minimum cost. This umbrella approach approach encompasses the other recommendations and coordinates them for utility'S recourses in the most maximum effectiveness effectiveness and channels all the utility's effective (the authors effective manner possible. Application to aging infrastructure infrastructure areas (the have seen it applied successfully to improve the "bang for the buck" obtained in too). It is described here in the context of and combined with very new systems, too). reliability and cost other solutions aimed at aging areas with poor service reliability performance, within traditional electric power systems.

REFERENCES REFERENCES R.E.Brown, et al, aI, "Spatial Load Forecasting Using Non-Uniform Areas" in Proceedings Proceedings of the IEEE T&D Conference, April, of April, 1999, R.E. Brown, et aI, al, "Reliability "Reliability and Capacity: A Spatial Load Forecasting Method for a Performance-Based Regulatory Environment," Environment," in Proceedings of Performance-Based Regulatory of the IEEE PICA Conference, Conference, May, 1999, San Jose M. V. Engel et al., aI., editors, Tutorial on Distribution Distribution Planning, IEEE Course Text EHO 361-6-PWR, Institute of of Electrical and Electronics Engineers, Hoes Lane, NJ, 1992. 1992. aI., "Load H. N. Tram et al., "Load Forecasting Data and Database Development for Distribution Apparatus and Systems, November 1983, p. 3660. Planning,"IEEE Trans. Planning,"//:^ Trans, on Power Power Apparatus

H. L. Willis, "Load Forecasting for Distribution Planning, Planning, Error and Impact on Design," Design," IEEE Transactions on Power Apparatus Apparatus and IEEE and Systems, March 1983, p. 675. 675. Powell, "Load Forecasting for Transmission Planning," Planning," IEEE H. L. Willis and R. W. Powell, Transactions on Power Apparatus Apparatus and and Systems, August 1985, p. 2550. Load Forecasting, Marcel Dekker, New York, 1996. H. L. Willis, Spatial Electric Load Distribution Planning Reference Book, Marcel Marcel Dekker, Dekker, New York, H. L. Willis, Power Distribution Planning Reference 1997.

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H. L. Willis and J. E. D. Northcote-Green, "Spatial Load Forecasting -~ A Tutorial Review," Proceedings of of the IEEE, Feb. 1983, p. 232.

H. L. Willis and H. N. Tram, "Load Forecasting for Transmission Planning," IEEE Trans, on Power Apparatus and Systems, paper 83 83 SM 379-5, March 1984. Trans. Apparatus and P. Carrier (Chairman), Interim Report of of the U.S. U.S. Department of Energy's Department of Energy's Power Outage Study Team: from the summer of Study Team: Findings from of 1999, United States Department of of Energy, Office of of Policy, Washington, January 2000

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2 Power Delivery Systems 2.1 INTRODUCTION 2.1 INTRODUCTION

Retail sale of of electric energy involves the delivery of of power in ready to use fonn form to the final consumers. Whether marketed by a local utility, load aggregator, or direct power retailer, this electric power must flow through a power delivery system on its way from power production to consumer. This transmission and distribution (T&D) system consists of of transmission and of thousands of distribution lines, substations, transformers, and other equipment scattered scattered over a wide geographical area and interconnected so that all function in concert to deliver power as needed to the utility's consumers. consumers. &0 systems, their mission, This chapter is a quick tutorial review on T T&D characteristics, and design constraints. It examines the natural phenomena that characteristics, shape T &0 systems and explains the key physical relationships and their impact T&D on design and performance. For this reason experienced planners are advised to scan this chapter, or at least its conclusions, so they understand the perspective upon which the rest of the book builds. concentrated at only a In a traditional electric system, power production is concentrated &0 system moves the power few large, usually isolated, power stations. The T T&D from those often-distant generating generating plants to the many consumers who consume the power. In some cases, cost can be lowered and reliability enhanced through the use of of distributed generation generation (OG): (DG): numerous smaller generators placed at

37 Copyright © 2001 by Taylor & Francis Group, LLC

38

Chapter 2

strategically selected points throughout the power power system in proximity to the consumers. 1I This and other distributed resources - so named because they are distributed throughout the system in close proximity to consumers - including storage systems and demand-side management, often often provide great benefit. But regardless of of the use of of distributed generation or demand-side management, the T&D T&D system is the ultimate ultimate distributed resource, consisting of of thousands, perhaps millions, of of units of of equipment scattered throughout the service territory, interconnected and operating in concert to achieve uninterrupted delivery of uninterrupted of power to the electric consumers. These systems represent an investment of of billions of of dollars, require care and precision in their operation, and provide widely available, economical, and reliable reliable energy. &D This chapter begins with an examination of of the role and mission of of a T T&D system: why it exists and what it is expected to do, in section 2.2. Section 2.3 looks at several fundamental physical "laws" that constrain T &D systems T&D of its design. The typical hierarchical system structure that results and the costs of equipment are summarized in sections 2.4, 2.5 and 2.6. In section 2.7, a number of of different different ways to layout lay out a distribution distribution system are covered, along with their advantages advantages and disadvantages. Section 2.8 covers the "systems approach," 1, and perhaps the single most important concept already mentioned in Chapter I, in the design of of retail electric delivery systems, which aim to be both inexpensive and reliable. reliable.

2.2 T&D SYSTEM'S SYSTEM'S MISSION

A T&D system's system's primary mission is to deliver power to electrical consumers at their place of of consumption and in ready-to-use ready-to-use form. form. This means it must be dispersed throughout the utility utility service territory in rough proportion to consumer locations and demand (Figure 2.1). This is the primary requirement T&D — the system must cover ground -— reaching every consumer for a T &D system -with an electrical path of of sufficient sufficient strength to satisfY satisfy that consumer's demand. That electrical path must be reliable, reliable, too, so that it provides an uninterrupted of stable power to the utility'S utility's consumers. Reliable power delivery means flow of delivering all of of the power demanded not just some of of the power needed, and doing so all of of the time. Anything less than near perfection in meeting this goal is considered unacceptable. While 99.9% reliability reliability of of service may sound of electric service interruption each year, impressive, it means nearly nine hours of unacceptable in nearly any first-world country. an amount that would be unacceptable

1

See W. See Distributed Power Generation - Planning and Evaluation. Evaluation, by by H. H. L. L. Willis and and W. G. Scott, Marcel Dekker, 2000. I

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39

Power Delivery Systems

2011 PEAK WINTER PEAK 3442 MW 3442MW N Ten miles miles Shading indicates relative relative load load density. Lines show major major roads highways. and highways.

Figure 2.1 Map of of electrical electrical demand demand for a major demand major US city shows where the total demand of of more than 2,000 MW peak is located. Degree of of shading indicates electric load distribution. The T&D system must cover the region with sufficient sufficient capacity at every location to meet the consumer consumer needs there. there. location

Beyond the need to deliver power to the consumer, the utility's T &D system T&D must also deliver it in ready-to-use form - at the utilization voltage required for equipment, and free of of large voltage fluctuations, fluctuations, high electrical appliances and equipment, aI., 1992). levels of of harmonics or transient electrical disturbances disturbances (Engel et al., Most electrical equipment in the United States is designed to operate properly when supplied with 60 cycle alternating current at between 114 and 126 volts, a plus or minus five percent range centered on the nominal utilization voltage of of the alternating voltage). In many other of 120 volts (RMS average of countries, utilization standards vary from 230 to slightly over 250 volts, at either 50 or 60 cycles AC. 22 But regardless of of the utilization voltage, a utility must must maintain the voltage provided to each consumer within a narrow range centered designed to tolerate. within the voltages that electric equipment is designed A ten- percent range of of delivery delivery voltage throughout a utility's service area may be acceptable, but a ten- percent range of of fluctuation in the voltage any one consumer is not. An instantaneous shift shift of of even three supplied to anyone 2 2

provided to consumers in the United States by reversed alternating current legs Power is provided (+ 120 volts and -120 -120 volts wire to ground). This scheme provides 240 volts of (+120 of power to distribution engineering engineering and performance, performance, of distribution any appliance that needs it, but for purposes of acts like only 120 volt power.

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40

Chapter 2

voltage causes a perceptible (and to some people, disturbing) flicker percent in voltage flicker lighting. More importantly, voltage fluctuations can cause erratic and in electric lighting. undesirable behavior of some electrical electrical equipment. Thus, whether high or low within the allowed range, the delivery voltage of of anyone any one consumer must be maintained at about the same level all the time normally within a range of three to six percent - and any fluctuation fluctuation must occur slowly. Such stable voltage can be difficult difficult to obtain, because the voltage at the consumer end of a T &D system varies inversely with electric demand, falling as T&D the demand increases, rising as it decreases. decreases. If this range of load fluctuation is too great, or if it happens too often, the consumers may consider it poor service. Thus, a T&D system's mission is to: I. 1. Cover the service territory, reaching all consumers 2. Have sufficient sufficient capacity to meet the peak demands of its consumers 3. Provide highly reliable delivery to its consumers

4. Provide stable voltage quality to its consumers consumers And of course, above everything everything else, achieve these four goals at the lowest cost possible. 2.3 THE "LAWS OF T&D"

The complex interaction of a T&D system is governed by a number of physical laws relating to the natural phenomena that have been harnessed to produce and move electric power. These These interactions have created created a number of "truths" that dominate the design of T&D systems: 1. It is more economical economical to move power at high voltage. The higher the voltage, the lower the costs per kilowatt to move power any distance.

2. The higher greater the capacity and the greater the higher the voltage, the greater cost of of otherwise similar similar equipment. Thus, high voltage lines, while potentially economical, cost a great deal more than low voltage lines, but have a much greater capacity. They are only economical in practice if they can be used to move a lot of power in one block - they are the giant economy size, but while always giant, they are only economical economical if one truly needs the giant size. 3.

of power. Utilization voltage is useless for for the transmission of power. The utilization voltage used in the United 120/240 volt single-phase utilization States, or even the 250 volt/416 voltl416 volt three-phase used in "European "European systems" is not equal to the task of economically moving power more than a few hundred yards. The application of these lower

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Power Delivery Systems

41

voltages for anything anything more than very local distribution at the neighborhood level results in unacceptably high electrical electrical losses and high costs. 4.

It is costly to change voltage level - not prohibitively so, for it is done throughout a power system (that's what transformers do) - but voltage transformation is a major expense, which does nothing to move the power any distance in and of itself.

5.

Power is more economical to produce in very large amounts. There is a significant economy of scale in generation, notwithstanding notwithstanding the modern distributed generators. Large claims by advocates of modem generators produce power more economically than small ones. Thus, efficient to produce power at a few locations utilizing large it is most efficient generators. 3

6.

Power must be delivered in relatively small quantities at low (120 to level. The average consumer has a total demand 250 volt) voltage level. equal to only 1I1O,OOOth l/10,000th or 1I100,OOOth 17100,000th of the output of a large generator.

An economical T T&D &D system builds upon these concepts. It must "pick up" many, many power at a few, few, large sites (generating plants), and deliver it to many, more small sites (consumers). It must somehow achieve economy by using high voltage, but only when power flow can be arranged so that large quantities quantities are moved simultaneously along a common path (line). Ultimately, power must be amounts, reduced to utilization voltage, and subdivided into "house-sized" amounts, routed to each business and home via equipment whose compatibility with individual consumer needs means it will be relatively inefficient inefficient compared to the system as a whole.

3 3

The issue is more complicated than than just a comparison comparison of the cost of big versus small generation, as will be addressed later in this book. In some cases, distributed distributed generation constraints provides the lowest cost overall, regardless of the economy of scale, due to constraints imposed &D system. Being close to the consumers, distributed generation imposed by the T T&D consumers, distributed generation does of adding T T&D not carry with it the costs of &D facilities to move the power from generation site to consumer. Often this is the margin of difference, as will be discussed discussed later in this book.

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42

Chapter 2

Levels Hierarchical Voltage Levels The overall concept of of a power delivery system layout that has evolved to best handle these needs and "truths" is one of of hierarchical hierarchical voltage levels as shown in Figure 2.2. As power is moved from generation (large bulk sources) to consumer (small demand amounts) it is first moved in bulk quantity at high voltage - this makes particular sense since there is usually usually a large bulk amount of of power to be moved out of a large generating plant. As power is dispersed throughout the service territory, it is gradually moved down to lower voltage levels, where it is moved in ever smaller amounts (along more separate paths) on lower capacity equipment until it reaches the consumers. The key element is a "lower "lower voltage and split" concept. Thus, the 5 kW used by a particular consumer -- Mrs. Rose at 412 Oak Street in Metropolis City - might be produced at a 750 MW power plant more than three hundred miles to the north. Her power is moved as part of of a 750 MW block from plant to city on a 345 kV transmission line, to a switching lowered to 138 138 kV through a 345 to 138 kV substation. Here, the voltage is lowered after that, the 750 MW block is split into five transformer, and immediately after of these five parts separate flows in the switching substation buswork, each of

Generating plant

_

345 kV transmission transmission 138 kV transmission 12.477 kV primary feeder 12.4 120/240 volt secondary

oo

I_ I switching substation substation substation • service transformer

Figure 2.2 A power system is structured in a hierarchical manner with various voltage levels. A key concept is "lower voltage and split" which is done from three to five times of power flow from generation to consumer. during the course of

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Power Delivery Systems

43

being roughly 150 150 MW. Now part of of a smaller block of of power, Mrs. Rose's electricity is routed to her side of of Metropolis on a 138 kV transmission line that snakes 20 miles through the northern part of of the city, ultimately connecting to another switching substation. This 138 kV transmission line feeds power to several distribution substations along its route,4 route,4 among which it feeds 40 MW neighborhoods, including Mrs. into the substation that serves a number of of neighborhoods, Rose's. Here, her power is run through a 138-kV/12.47kV-distribution transformer. As it emerges from the low side of of the substation distribution transformer at 12.47 kV (the primary distribution voltage) the 40 MW is split into six parts, each about 7 MW, with each 7 MVA MV A part routed onto a different different distribution feeder. Mrs. Rose's power flows along one particular feeder for two miles, until it gets to within a few hundred feet of of her home. Here, a much smaller amount of of power, 50 kVA (sufficient (sufficient for perhaps ten homes), is routed to a service transformer, one of of several hundred scattered up and down the length of the feeder. As Mrs. Rose's power flows through the service transformer, it is reduced to 120/240 volts. As it emerges, it is routed onto the secondary secondary system, operating at 120/240 volts (250/416 (250/416 volts in Europe and many other countries). The secondary wiring splits the 50 kVA kV A into small blocks of of power, each about 5 kVA, kVA, and routes one of these to Mrs. Rose's home along a secondary conductor conductor to her service drops - the wires leading directly to her house. Over the past one hundred years, this hierarchical system structure has proven a most effective effective way to move and distribute power from a few large generating plants to a widely dispersed consumer base. The key element in this structure is the "reduce of the power "reduce voltage and split" function - a splitting of flow being done simultaneously with a reduction in voltage. Usually, this happens between three and five times as power makes its way from generator to consumers. 2.4 2.4 LEVELS LEVELS OF THE T&D T&D SYSTEM

As a consequence of this hierarchical structure, a power delivery system can be of very conveniently to be composed of thought of of several distinct levels of of equipment, as illustrated in Figure 2.3. Each level consists of of of many units of fundamentally similar equipment, doing roughly the same job, but located in different parts of of the system. For example, all ofthe of the distribution substations different

4 4

Transmission lines whose sole or major function is to feed power to distribution substations are often referred to as "sub-transmission" "sub-transmission" lines.

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Chapter 2

44

Generation G:nraim --------..-===~.~~.===.~====~,.-========= .. ~===---~~ •



Tnansrrisskn Subfransrrisskn Substation Feeders Savioe Customer North

&0 system consists of delivery equipment, Figure 2.3 A T T&D of several levels levels of of power delivery equipment, each feeding the one below it.

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Power Delivery Systems

45

are planned and laid out in approximately the same manner and do roughly the same job. Likewise, all feeders are similar in equipment type, layout, and mission, and all service transformers have the same basic mission and are designed with similar planning goals and to similar engineering standards. Power can be thought of of as flowing "down" through these levels, on its way from power production to consumer. As it moves from the generation plants (system level) to the consumer, the power travels through the transmission level, to the sub-transmission level, to the substation level, through the primary feeder level, and onto the secondary service level, where it finally reaches the consumer. Each level takes power from the next higher level in the system and delivers it to the next lower level in the system. While each level varies in the types of of equipment it has, its characteristics, mission, and manner of of design and characteristics: planning, all share several common characteristics:

level is is fed fed power by the the one one above it, it, in in the sense that the the next • Each level higher level is electrically closer to the generation. the nominal nominal voltage level level and and the the average capacity of equipment • Both the drops from level to level, as one moves from generation to consumer. Transmission lines operate at voltages of of between 69 kV and 1,100 kV Transmission and have capacities between 50 and 2,000 MW. By contrast, distribution feeders operate between 2.2 kV and 34.5 kV and have capacities somewhere between 2 and 35 MW. has many more pieces of equipment in in itit than the the one • Each level has above. A system with several hundred thousand consumers might have fifty transmission lines, one hundred substations, fifty substations, six hundred feeders, and forty thousand service transformers. As a result, the the net net capacity of each level (number of units times • As average size) increases as one moves toward the consumer. A power MV A system might have 4,500 MV A of MVA of substation capacity but 6,200 MVA of of feeder capacity and 9,000 MVA of of service transformer capacity installed. 55 Reliability drops as as one one moves moves closer to to the consumer. A majority of • Reliability of failure (either due to aging or to service interruptions are a result of of transformers, connectors, or damage from severe weather) of conductors very close to the consumer, as shown in Figure 2.4.

5 5

This greater-capacity-at-every-level is deliberate and required required both for reliability reasons and to accommodate coincidence of of load, which will be discussed in Chapter 3.

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46

Chapter 2 Ten-year Service Interruption Statistics by Level Level of Cause

15

110

o

Generation

Trans.

Subs.

Feeders

Service

Level of the Power System

Figure grouped by Figure 2.4 Ten years of of consumer interruptions for a large electric system, grouped generation and transmission often receive the most level of of cause. Interruptions Interruptions due to generation attention because they usually usually involve a large number of consumers attention consumers simultaneously. However, such events are rare whereas distribution level whereas failures and interruptions at the distribution create of interruptions. create a constant constant background background level of

Table 2.1 2.1 gives statistics for a typical system. The net effect effect of of the changes changes in average average size and number of of units is that each level contains a greater greater total capacity than the level above it. The service transformer level in any utility considerably more installed capacity system has considerably capacity (number (number of units times average capacity) than the feeder system or the substation system. Total capacity increases as one heads toward the consumer because of non-coincidence of of peak load (which will be discussed in Chapter 3) and for reliability purposes. purposes.

Table 2.1 Equipment Level Statistics for a Medium-Sized Electric System Level of System System of

Voltage kV

Number of of Units

Transmission Sub-transmission. Substations Feeders Feeders Service Trans. Trans. Secondary/Service Secondary/Service Consumer Consumer

12 345, 138 138,69 25 69/13.8 139/23.9, 69113.8 45 23.9, 227 23.9, 13.8 60,000 60,000 .12, .24 250,000 250,000 .12, .24 .12 250,000 250,000

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Avg. Cap. MVA

Total Cap MVA

150 65 44 11 .05 .014 .005

1,400 1,525 1,980 2,497 3,000 3,500 1,250

47

Power Delivery Systems The Transmission Level

The transmission system is a network of three-phase lines operating at voltages generally between 115 kV and 765 kV. Capacity of of each line is between 50 MV A and 2,000 MVA. MV A. The term "network" means that there is more than one MVA electrical path between any two points in the system (Figure 2.5). Networks are laid out in this manner for reasons of of reliability and operating flow--if flow—if anyone any one element (line) fails, there is an alternate route and power flow is (hopefully) not interrupted. In addition to their function in moving power, portions of of the transmission system, the largest elements, namely its major power delivery lines, are designed, at least in part, for stability needs. The transmission grid provides a strong electrical tie between generators, so that each can stay synchronized with the system and with the other generators. This arrangement allows the system to operate and to function evenly as the load fluctuates fluctuates and to pick up load smoothly if any generator fails - what is called stability of of operation. A good of the equipment put into transmission system design, and much of of its cost, deal of is for these stability reasons, not solely or even mainly, mainly, for moving power.

D-

Figure 2.5 A network is an electrical system with more than one path between any two points, meaning that (if (if properly designed) it can provide electrical service even if if any one element fails.

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48

Chapter 2

The Sub-transmission Level

The sub-transmission lines in a system take power from the transmission switching stations or generation plants and deliver it to substations along their routes. A typical sub-transmission line may feed power to three or more substations. Often, portions of of the transmission system, bulk power delivery lines, lines designed at least in part for stability as well as power delivery needs to do this too. The distinction between transmission and sub-transmission lines becomes rather blurred. A up Normally, sub-transmission sub-transmission lines are in the range of capacity of of 30 MV MVA to perhaps 250 MVA, MV A, operating at voltages from 34.5 kV to as high as 230 kV. With occasional occasional exceptions, sub-transmission lines are part of of a network grid they are part of of a system in which there is more than one route between any two points. Usually, at least two sub-transmission sub-transmission routes flow into anyone any one substation, so that feed can be maintained if one fails. 6 The Substation Level Level

Substations, the meeting point between the transmISSIOn transmission grid and the distribution feeder system, are where a fundamental fundamental change takes place within most T&D systems. The transmission and sub-transmission systems above the substation level usually form a network, as discussed above, with more than one power flow path between any two parts. But from the substation on to the consumer, arranging a network configuration would simply be prohibitively prohibitively expensive. Thus, most distribution systems are radial - there is only one path through the other levels of of the system. Typically, a substation occupies an acre or more of of land on which the necessary substation equipment is located. Substation equipment consists of necessary of high and low voltage racks and busses for the power flow, circuit breakers for both the transmission and distribution level, level, metering equipment, and the "control house," where the relaying, relaying, measurement, and control equipment is located. But the most important equipment, what gives this substation its capacity rating, are the substation transformers. These transformers convert the incoming power from transmission voltage levels to the lower primary voltage for distribution. A Individual substation transformers vary in capacity, from less than 10 MV MVA MVA. often equipped with tap-changing to as much as 150 MV A. They are often

6 6

Radial transmission Radial feed - only one line - is is used in isolated, isolated, expensive, or difficult transmission situations, but for reliability reasons is not recommended.

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Power Delivery Systems

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mechanisms and control equipment to vary their winding ratio so that they maintain the distribution voltage within a very narrow range, regardless of of larger fluctuations on the transmission side. The transmission voltage can swing by as much as 5%, but the distribution voltage provided on the low side of of the transformer stays within a narrow band, perhaps only ± .5%. Very often, a substation will have more than one transformer. Two is a common number, four is not uncommon, and occasionally six or more are located at one site. Having more than one transformer increases reliability. In increases reliability. transformer can handle a load much over its rated load for a an emergency, a transformer brief brief period (e.g., perhaps up to 140% of of rating for up to four hours). Thus, the T &D system can pick up the load of brief repairs T&D of the outaged portions during brief and in emergencies. Equipped with one to six transformers, substations range in "size" or MVA capacity from as little as five MV A for a small, single-transformer substation, MVA A for a truly large serving a sparsely populated rural area, to more than 400 MV six-transformer station, serving a very dense area within a large city. &D planners will speak of Often Often T T&D of a transformer transformer unit, which includes the transformer and all the equipment necessary to support its use - "one "one fourth of of the equipment in a four-transformer substation." This is a much better way of of &D plans. While a thinking about and estimating cost for equipment in T T&D transformer itself itself is expensive (between $50,000 and $1,000,000); the buswork, control, breakers, and other equipment required to support its use can double or triple that cost. Since that equipment is needed in direct proportion to the only because a transformer's capacity and voltage, and since it is needed only transformer is being added, it is normal to associate it with the transformer as a single planning unit. Add the transformer and add the other equipment along with it. Substations consist consist of of more equipment and involve more costs than just the electrical equipment. The site has to be purchased and prepared. Preparation is not trivial. The site must be excavated, a grounding mat - wires running under the substation to protect against an inadvertent flow during emergencies - laid foundations and control ducting for equipment must be installed. down, and foundations Transmission towers to terminate incoming transmission must be built. Feeder getaways - ducts or lines to bring power out to the distribution system - must be added. The Feeder Level Level Feeders, typically either overhead distribution lines mounted on wooden poles or underground underground buried or ducted cable sets, route the power from the substation throughout its service area. Feeders operate at the primary distribution voltage.

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Chapter 2

50

distribution voltage in use throughout North The most common primary distribution America is 12.47 kV, although anywhere from 4.2 kV to 34.5 kV is widely kVand used. Worldwide, there are primary distribution voltages as low as 1.1 1.1 kV and as high as 66 kV. Some distribution distribution systems use several primary voltages - for example 23.9 kV, 13.8 kV and 4.16 kV. A feeder is a small transmission transmission system in its own right, distributing between A to more than 30 MV A, depending on the conductor size and the 2 MV MVA MVA, distribution voltage level. level. Normally between two and 12 feeders emanate from anyone any one substation, in what has been called a dendrillic configuration - repeated branching into smaller branches as the feeder moves out from the substation toward the consumers. In combination, all the feeders in a power system feeder system (Figure 2.6). An average substation has between constitute the feeder two and eight feeders, and can vary between one and forty feeders. of a feeder is called the primary primary trunk and may The main, three-phase trunk of branch into several main routes, as shown in the diagram on the next page. of These main branches end at open points where the feeder meets the ends of other feeders - points at which a normally normally open switch serves as an emergency tie between two feeders.

d substation substation [] closed switch switch •• closed O open open switch switch o

— primary trunk — lateral, branches

Three miles

N

1

Figure 2.6 Distribution Distribution feeders route power away from the substation, as shown (in idealized form - configuration is never so evenly symmetric in the real world) for two substations. Positions of of switches make the system electrically radial, while parts of of it are physically a network. Shown here are two substations, each with four feeders.

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nonnally closed switches into several switchable elements will Additionally, normally divide each feeder. feeder. During emergencies, segments can be re-switched to isolate damaged sections and route power around outaged equipment to consumers who would otherwise have to remain out of of service until repairs were made. By definition, definition, the feeder consists of of all primary voltage level segments between the substations and an open point (switch). Any part of of the distribution level voltage lines - three-phase, two-phase, or single-phase - that is switchable is considered part of of the primary feeder. feeder. The primary trunks and switchable segments are usually built using three phases. The largest size of of distribution conductor (typically this is about 500-600 MCM conductor, but conductor over 1,000 MCM is not uncommon, and the author has feeders with 2,000 MCM conductor) being used for reasons other than just maximum capacity (e.g., contingency switching needs). Often a feeder has excess capacity because it needs to provide back up for other feeders during emergencies. emergencies. The vast majority of of distribution feeders feeders used worldwide and within the United States are overhead construction, wooden pole with wooden crossann crossarm or post insulator. Only in dense urban areas, or in situations where esthetics are particularly important, can the higher cost of of underground construction be justified. In this case, the primary feeder is built from insulated cable, which is pulled through concrete ducts that are first buried in the ground. Underground feeder costs are three to ten times that of overhead costs. Many times, however, the first several hundred yards of of an overhead primary feeder are built underground even if the system is overhead. This underground portion is used as the feeder feeder get-away. Particularly at large substations, the reliability underground get-away is dictated by practical necessity, as well as by reliability and esthetics. At a large substation, ten or twelve 3-phase, overhead feeders leaving the substation mean from 40 to 48 wires hanging in mid-air around the substation substation site, with each feeder needing the proper spacing for electrical insulation, safety, and maintenance. One significant aging infrastructure issue is that at many large-capacity large-capacity substations in a tight location, there is simply not enough overhead space for enough feeders to be routed out of if there is, the resulting of the substation. Even if tangle of potentially of wires looks unsightly, unsightly, and perhaps most importantly, is potentially unreliable. One broken wire falling in the wrong place can disable a lot of of power delivery capability. The solution to this dilemma is the underground feeder getaway, usually consisting consisting of of several hundred yards of buried, ducted cable that takes the feeder out to a riser pole, where it is routed above ground and connected to overhead wires. Very often, this initial underground link sets the capacity limit for the entire feeder. underground cable ampacity is the feeder. The underground limiting factor for the feeder's power transmission. transmission.

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52

Chapter 2

The Lateral Level

Laterals are short stubs or line-segments that branch off off the primary feeder and represent the final primary voltage part of the power's journey from the substation to the consumer. A lateral is directly connected to the primary trunk and operates at the same nominal voltage. A series of of laterals tap off off the primary feeder as it passes through a community, each lateral routing power to a few dozen homes. Normally, laterals do not have branches, and many laterals are only one or of two-phase. All three phases are used only if a relatively relatively substantial amount of of the power is required, or if three-phase service must be provided to some of arranged to tap consumers. Normally, single and two-phase laterals are arranged alternately different different phases on the primary feeder. An attempt by the Distribution Planning Engineer to balance the loads as closely as possible is shown below. Typically, laterals deliver from as little as 10 kVA for a small single-phase lateral, to as much as 2 MV A. In general, even the largest laterals use small MVA. conductors (relative to the primary size). When a lateral needs to deliver a great deal of of power, the planner will normally use all three phases, with a relatively conductor for each, rather than employ a single-phase and use a large small conductor conductor. This approach avoids creating a significant imbalance in loading at the point where the lateral taps into the primary feeder. Power flow, loadings and voltage are maintained in a more balanced state if the power demands of of a "large lateral" are distributed over all three phases. Laterals (wooden poles) are built overhead or underground. Unlike primary feeders and transmission lines, single-phase single-phase laterals are sometimes buried directly. In this case, the cable is placed inside a plastic sheath (that looks and feels much like a vacuum cleaner hose). A trench is dug, and the sheathed cable is unrolled into the trench and buried. Directly buried laterals are no more expensive than underground construction in many cases. The Service Transformers Transformers

Service transformers lower voltage from the primary voltage to the utilization or consumer consumer voltage, normally 1201240-volt 120/240-volt two-leg service in most power systems throughout North America. In overhead construction, service transformers are pole mounted and single-phase, single-phase, between 5-kVA and 166 -kVA capacity. There may be several hundred scattered along the trunk and laterals of of any given feeder; feeder; since power can travel efficiently efficiently only up to about 200 feet at utilization voltage, there must be at least one service transformer located reasonably close to every consumer.

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transfonners, power is lowered in voltage once again, Passing through these transformers, to the final utilization voltage (120/240 volts in the United States) and routed to the secondary system or directly to the consumers. In cases where the system is supplying power to large commercial or industrial consumers, or the consumer requires three-phase power, between two and three transformers transfonners may be located together in a transformer transfonner bank, and be interconnected in such a way as to different connection schemes are possible provide multi-phase power. Several different for varying situations. Padmount, or vault-type, service transformers transfonners provide underground service, as opposed to overhead pole-mounted service. The concept is identical to overhead construction, with the transfonner transformer and its associated equipment changed to accommodate incoming and outgoing lines that are underground.

The Secondary and Service Level Secondary circuits fed by the service transfonners, transformers, route power at utilization voltage within very close proximity to the consumer. Usually this is an of arrangement in which each transformer transfonner serves a small radial network of utilization voltage secondary and service lines. lines. These lead directly to the meters of of consumers in the immediate immediate vicinity. At most utilities, utilities, the layout and design of of the secondary level is handled through a set of of standardized guidelines and tables. Engineering technicians use these and clerks to produce work orders for the utilization voltage level equipment. In the United States, the vast majority ofthis of this system is single-phase. In European systems, much of the secondary is 3-phase, particularly in urban and suburban areas. What is Transmission and what is Distribution?

Definitions and nomenclature defining "transmission" and "distribution" vary different countries, companies, and power systems. Generally, greatly among different of distinction between the two are made: three types of 1.

By voltage class: transmission is anything above 34.5 kV; distribution is anything below that.

2.

By function:

distribution includes all utilization voltage equipment, plus all lines that feed power to service transfonners. transformers.

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3.

By configuration: configuration:

transmission includes a network; transmISSIOn distribution is all the radial equipment in the system.

Generally, all three definitions definitions apply simultaneously since in most utility systems any transmission above 34.5 kV is configured as a network and does not feed service transformers directly. directly. On the other hand, all distribution is radial, built of of only 34.5 kV or below, and does feed service transformers. transmission lines (incoming) (incoming) and and the meeting places of transmission Substations - the distribution lines (outgoing) - are are often included in one one or the other category, and sometimes are considered as separate entities.

UTILITY DISTRIBUTION EQUIPMENT 2.5 UTILITY The preceding section made it clear that a power delivery system is a very complex entity, composed of millions, of of thousands, perhaps even millions, of components, which function together as a T&D system. Each unit of of equipment has only a small part to play in the system, and is only a small part of of the cost, yet each is critical for satisfactory service to at least one or more consumers or it would not be included in the system. T &D system planning is complex because each unit of influences T&D of equipment influences the electrical behavior of of its neighbors. It must be designed to function well in conjunction with the rest of of the system, under a variety of of different different conditions, of loads or the status of regardless of of shifts in the normal pattern of of equipment nearby. While the modeling and analysis of of a T&D system can present a significant individually its components are relatively simple to significant challenge, individually of understand, engineer, and plan. In essence, there are only two major types of equipment that perform the power delivery function: 1.

transmission and distribution distribution lines lines which move power from one location to another

2.

transformers which change the voltage level of of the power

Added to these three basic equipment types are two categories of of equipment used for a very good reason: I. 1. Protective equipment which provides safety and "fail safe" operation

2. Voltage regulation equipment, equipment, which is used to maintain voltage within an acceptable range as the load, changes. Monitoring and

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control equipment used to measure equipment and system performance and feed this information to control systems so that the utility knows what the system is doing and can control it, for both safety and efficiency efficiency reasons. Transmission Transmission and Distribution Lines Lines

By far the most omnipresent part of of the power distribution system is the portion portion another. devoted to actually moving the power flow from one point to another. Transmission lines, sub-transmission lines, feeders, laterals, secondary and service drops, all consist of electrical conductors, suitably protected by isolation (transmission towers, insulator strings, and insulated wrappings) from voltage leakage and ground contact. It is this conductor that carries the power from one location to another. Electrical conductors are available in various capacity ranges, with capacity generally corresponding to the metal cross section (other things being equal, thicker wire carries more power). Conductors can be all steel (rare, but used in some locations where winter ice and wind loadings are quite severe), all aluminum, or copper, or a mixture of of aluminum and steel. Underground transmission can use various types of high-voltage cable. Line capacity depends on the current-carrying current-carrying capacity of of the conductor or the cable, the voltage, the number of of phases, and constraints imposed by the line's location in the system. The most economical method of of handling a conductor is to place it overhead, of supported by insulators on wooden poles or metal towers suitably clear of interference or contact with persons or property. However, underground construction, while generally more costly, avoids esthetic intrusion of of the line and provides some measure of of protection from weather. It also tends to reduce differences between underground cable the capacity of of a line slightly due to the differences and overhead conductor. Suitably wrapped with insulating material in the form of of underground cable, the cable is placed inside concrete or metal ducts or surrounded in a plastic sheath. Transmission/sub-transmission lines are always 3-phase. There are three separate conductors for the alternating current, sometimes with a fourth neutral (un-energized) wire. Voltage is measured between phases. A 12.47 kV distribution feeder has an alternating current voltage (RMS) of of 12,470 volts as measured between any two phases. Voltage between any phase and ground is 7,200 volts (12.47 divided by the square root of of three). Major portions of a

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distribution system - trunk feeders - are as a rule built as three-phase lines, but lower-capacity portions may be built as either two-phase, or single-phase. 7 Regardless of of type or capacity, every electrical conductor has impedance (a resistance to electrical flow through it) that causes voltage drop and electrical losses whenever it is carrying electric power. Voltage drop is a reduction in the voltage between the sending and receiving ends of the power flow. Losses are a reduction in the net power, and are proportional to the square of of the power. Double the load and the losses increase by four. fOUf. Thus, 100 kilowatts at 120 volts might go in one end of of a conductor, only to emerge at the other as 90 kilowatts at 114 volts at the other end. Both voltage drop and losses vary in direct relation to load - within very fine limits if there is no load, there are no losses or voltage drop. Voltage drop is proportional to load. Double the load and voltage drop doubles. Losses are quadratic, however. Double the load and losses quadruple. Transformers Transformers At the heart of of any alternating power system are transformers. They change the voltage and current levels of of the power flow, maintaining maintaining (except for a very small portion of of electrical losses), the same overall power flow. If If voltage is multiplied reduced by a factor of of ten from the high to low side, then Current is multiplied by ten, so that their overall product (Voltage times Current equals Power) is constant in and out. Transformers are available in a diverse range of of types, sizes, and capacities. They are used within power systems in four major areas: I. 1.

2.

3.

4.

generated at about At power plants, where power which is minimally generated transmission voltage (l00,000 20,000 volts is raised to transmission (100,000 volts or higher) At switching stations, where transmission voltage is changed (e.g., from from 345,000 volts to 138,000 volts before splitting onto lower voltage transmission lines) At distribution distribution substations, where incoming transmission-level voltage is reduced to distribution voltage for distribution (e.g., 138 kV to 12.47 kV) And at service transformers, where power is reduced in voltage from the primary feeder voltage to utilization level (12.47 kV to 120/240 volts) for routing into consumers' homes and businesses.

7 7

In most cases, a single-phase single-phase feeder or lateral has two conductors: conductors: the phase conductor and the neutral.

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Larger transfonners transformers are generally built as three-phase units, in which they simultaneously transfonn transform all three phases. Often these larger units are built to custom or special specifications, and can be quite expensive - over $3,000,000 per unit in some cases. Smaller transfonners, transformers, particularly most service transfonners, transformers, are single-phase - it takes three installed sides by side to handle a full three-phase line's power flow. They are generally built to standard specifications and bought in quantity. Transfonners Transformers experience two types of of electrical losses - no-load losses (often (often called core, or iron, losses) and load-related losses. No-load losses are electrical losses inherent in operating the transformer transfonner - due to its creation of a magnetic transformer is connected to field inside its core. They occur simply because the transfonner an electrical power source. They are constant, regardless of of whether the power flowing through the transformer transfonner is small or large. No-load losses are typically typically transfonner is less than one percent of the nameplate rating. Only when the transformer seriously overloaded, to a point well past its design range, will the core losses change (due to magnetic saturation of of the core). Load-related losses are due to the current flow through the transformer's transfonner's impedance and correspond very directly with the level of of power flow. Like those of of conductors and cables they are proportional to current squared or quadrupling whenever power flow doubles. The result of of both types of of losses is that a transfonner's transformer's losses vary as the power transmitted through it varies, but always at or above a minimum minimum level set by the no-load losses. Switches

Occasionally, it is desirable to be able to vary the connection of of line segments within a power delivery system, particularly in the distribution feeders. Switches are placed at strategic locations so that the connection between two segments can be opened or closed. Switches are planned to be normally nonnally closed (NC) or normally nonnally open (NO), as was shown in Figure 2.6. Switches vary in their rating (how much current they can vary) and their load off), with larger break capacity (how much current they can interrupt or switch off), switches being capable of of opening a larger current. They can be manually, automatically, or remotely controlled in their operation. Protection

When electrical equipment fails, for example if if a line is knocked down during a stonn, nonnal function of storm, the normal of the electrical equipment is interrupted. Protective equipment is designed to detect these conditions and isolate the damaged equipment, even if if this means interrupting the flow of of power to some

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disconnects, along with consumers. Circuit breakers, sectionalizers, and fused disconnects, control relays and sensing sensing equipment, are used to detect unusual conditions and interrupt the power flow whenever a failure, fault, or other unwanted condition occurs on the system. These devices and the protection engineering required to apply them properly to the power system are not the domain of of the utility planners and will not be discussed here. Protection is vitally important, but the planner is sufficiently involved with protection if he or she produces a system design that sufficiently can be protected within standards, and if the cost of of that protection has been taken into account in the budgeting and planning process. Both of of these considerations are very important. Protection puts certain constraints on equipment size and layout - for example, in some cases a very large conductor is too large (because it would permit too high a short circuit current) to be protected safely by available equipment and cannot be used. In other cases, long feeders are too long to be protected (because they have too low Iowaa short circuit current at the far end). A good deal of of protective equipment is quite complex, containing sensitive electro-mechanical parts, (many of of which move at high speeds and in a splitsecond second manner), and depending on precise calibration and assembly for proper function. As a result, the cost of of protective equipment and control and the cost of of its maintenance are often significant. significant. Differences in protection cost can make deciding difference difference between two plans. the deciding Voltage Regulation Voltage regulation equipment includes line regulators and line drop compensators, as well as tap changing transformers. These devices vary their turns-ratio (ratio of of voltage in to voltage out) to react to variations in voltage drop. If If voltage drops, they raise the voltage, if voltage rises, they reduce it to compensate. Properly used, they can help maintain voltage fluctuation on the system within acceptable limits, but they can only reduce the range of of eliminate it altogether. fluctuation, not eliminate Capacitors Capacitors

Capacitors are a type of voltage regulation equipment. By correcting power factor they can improve voltage under many heavy loads (hence large voltage of how well voltage and current in an drop) cases. Power factor is a measure of alternating system are in step with one another. In a perfect system, voltage and alternately cycle in conjunction with one another - reaching a current would alternately peak, then reaching a minimum, at precisely the same times. times. But on distribution systems, particularly under heavy load conditions, current and voltage fall out of of

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phase. Both continue to alternate 60 times a second, but during each cycle of voltage may reach its peak slightly ahead of of current - there is a slight lag of current versus voltage, as shown in Figure 2.7. It is the precise, simultaneous peaking of of both voltage and current that delivers maximum power. If If out of phase, even by a slight amount, effective effective power drops, as does power factor - the ratio of of real (effective) (effective) power to the maximum possible power, if if voltage and current were locked in step. Power engineers refer to a quantity called V ARs (Volt-Amp Reactive) that is VARs caused by this condition. Basically, as power factors worsen (as voltage and current fall farther apart in terms of of phase angle) a larger percent of of the ARs, and a smaller part is real power. The frustrating thing electrical flow is V VARs, is that the voltage is still there, and the current is still there, but because of of the shift ARS, not power. The worse the power shift in their timing, they produce only V VARS, factor, the higher the V AR content. Poor power factor creates considerable cost VAR and performance consequences for the power system: large conductor is still required to carry the full level of of current even though power delivery has dropped. And because current is high, the voltage drop is high, too, further further degrading quality of of service. Unless one has worked for some time with the complex variable mathematics associated with AC power flow analysis, VARs VARs are difficult difficult to ARs as "electrical If one tried picture. A useful analogy is to think of of V VARs "electrical foam." If to pump a highly carbonated soft soft drink through a system of of pipes, turbulence in the pipes, particularly in times of of high demand (high flow) would create foam. The foam would take up room in the pipes, but contribute little value to the net flow - the equivalent ofVARs of VARs in an electrical system. of loads create V VARs Poor power factor has several causes. Certain types of ARs loads that cause a delay in the current with respect to voltage as it flows through them. Among the worst offenders are induction motors - particularly particularly small ones as almost universally used for blowers, air conditioning compressors, and the powering of of conveyor belts and similar machinery. Under heavy load conditions, voltage and current can get out of phase to the point that power factor can drop below 70%. Additionally, transmission equipment equipment itself itself can often create this lag and "generate" a poor power factor.

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Chapter 2 VOLTAGE

L-------\-----+tTim e Time

VOLTAGE

Time f~-----\-----+"?Time

!

lag

n

L - - - - - - \ - - - - - + " ? T i >Time m e '-+_ _ _ _-\-_ _ _---# Time

CURRENT

CURRENT

maximum power (left). If Figure 2.7 Current and voltage in phase deliver deliver maximum If current and voltage fall out of of phase (right), (right), actual power delivered delivered drops by very noticeable amounts — the power factor falls. -factor falls.

Capacitors ARs into a T &D Capacitors correct correct the poor power factor. factor. They "inject" V VARs T&D line to bring power factor close to 1.0, transforming VAR VAR flow back into real flow, regaining the portion of power flow, of capacity lost to poor power power factor. Capacitors can involve considerable cost depending on location and type. They tend to do the most good if put on the distribution system, near the consumers, consumers, but they cost a great deal more in those locations than if installed installed at substations.

COSTS 2.6 T&D COSTS T&D AT &D system can be expensive to design, build, and operate. Equipment at every level incurs two types of of costs. Capital costs include the equipment and land, labor for site preparation, construction, assembly and installation, and any associated with building and putting the equipment into operation. operation. other costs associated Operating costs include labor and equipment for operation, maintenance and service, taxes and fees, as well as the value of of the power lost to electrical losses. Usually, capital costs are a one-time cost (once it's built, built, the money's been spent). Operating costs are continuous or periodic. Electrical losses vary depending on load and conditions. While these losses are small by comparison to the overall power being distributed (seldom more than 8%), they constitute a very real cost to the utility. utility. The present worth of the lifetime losses through a major system component such as a feeder or transformer can be a significant significant factor impacting its design and specification, often more than the original capital cost of of the unit. Frequently, a more costly of transformer will be selected for a certain application because its design type of

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leads to overall savings due to lower losses. Or a larger larger capacity capacity line (larger conductor) will be used when really needed needed due to capacity requirements, purely because the larger conductor will incur lower cost losses. because Cumulatively, the T&D system represents considerable expense. represents a considerable expense. While a few transmission lines and switching stations are composed composed of large, expensive, and purpose-designed purpose-designed equipment, the great great portion portion of the sub-transmissionsubstation-distribution system is built from "small "small stuff' stuff - commodity equipment bought mostly "off "off the shelf' shelf to standard designs. Individually inexpensive, they amount to a significant cost when added together. together. Transmission Transmission Costs Costs

Transmission Transmission line costs are based on a per-mile cost and a termination cost at associated with the substation at which it is terminated. either end of the line associated Costs can run from as low as $50,000/mile for a 46 kV wooden pole subA-mile) to over transmission line with perhaps 50 MVA capacity ($1 ($1 per kV kVA-mile) $1,000,000 per mile for a 500 kV double circuit construction with 2,000 MVA MV A capacity ($.5/kVA-mile).

Costs Substation Costs Substation costs include all the equipment and labor required required to build a easements/ROW. For planning substation, including the cost of land and easementslROW. purposes, substations can be thought of as having four costs:

1. Site cost - the cost of buying the site and preparing preparing it for a 1. substation. 2. Transmission cost - the cost of terminating the incoming subtransmission lines at the site. 3. Transformer Transformer cost - the transformer and all metering, control, oil spill containment, fire prevention, cooling, noise abatement, and other transformer related equipment, along with typical buswork, switches, metering, relaying, and breakers breakers associated associated with this type of transformer, and their installation.

4. Feeder busworkiGetaway buswork/Getaway costs - the cost of beginning distribution at the substation, includes getting feeders out of the substation.

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of feeder buswork and getaways are To expedite planning, estimated costs of often folded into the transformer costs. The feeders to route power out of of the substation are needed in conjunction with each transformer and in direct proportion to the transformer capacity installed, so that their cost is sometimes sometimes considered together with the transformer as a single unit. Regardless, the transmission, transformer, and feeder costs can be estimated fairly accurately for planning purposes. Cost of of land is another matter entirely. entirely. Site and easements or ROW into a of local land prices, which vary greatly site have a cost that is a function of depending on location and real estate markets. Site preparation includes the cost of of preparing the site which includes grading, grounding mat, foundations, foundations, buried ductwork, control building, building, lighting, lighting, fence, landscaping, and an access road. Substation costs vary greatly depending on type, capacity, local land prices and other variable circumstances. In rural settings where load density is quite of only low and minimal minimal capacity is required, required, a substation may involve a site of several thousand square feet of of fenced area. This single area includes a single incoming transmission line (69 kV), kY), one 5 MVA MY A transformer; fusing for all fault protection; and all "buswork" built with wood poles and conductor, for a total cost of of perhaps no more than $90,000. The substation would be applied to serve a load of perhaps 4 MW, for a cost of of $23/kW. This substation in conjunction with the system around it would probably provide service with about ten hours of of service interruptions per year under average conditions. However, a typical substation built in most suburban and urban settings would be fed by two incoming 138 kY kV lines lines feeding two 40 MY MVA, 138 kY kV to A, 138 12.47 kV kY transformers. These transformers would each feed a separate low side (12.47 kV) kY) bus, each bus with four outgoing distribution feeders of A of 9 MY MVA substation's peak capacity each, and a total cost of perhaps $2,000,000. Such a substation's cost could vary from between about $1.5 million and $6 million, million, depending on land costs, labor costs, the utility equipment and installation standards, and other special circumstances. In most traditional traditional vertically integrated, publicly regulated electric utilities, utilities, this substation would have been used to serve a peak MY A (75% utilization of load of of about 60 MVA of capacity), meaning that at its nominal $2,000,000 cost works out to $33/kW. In a competitive industry, with tighter design margins and proper engineering measures taken beforehand, this could be pushed to a peak loading of 80 MY MVA utilization, $25/k $25/kW). A (100% utilization, W). This substation and the system around it would probably provide service with about two to three hours of of service interruptions per year under "normal," average average conditions.

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Feeder System Costs Costs

The feeder system consists of of all the primary distribution lines, including threephase trunks and their lateral extensions. These lines operate at the primary distribution and distribution voltage - 23.9 kV, kV, l3.8 13.8 kV, kV, 12.47 kV, kV, 4.16kV or whatever - and may be three, two, or single-phase construction construction as required. Typically, the feeder system is also considered to include voltage regulators, capacitors, voltage boosters, sectionalizers, switches, cutouts, fuses, and any intertie transformers (required to connect feeders of of different different voltage at tie points - for example: 23.9 and 12.47 kV) that are installed on the feeders (not at the substations or at consumer facilities). As a rule of of thumb, construction of three-phase three-phase overhead, wooden pole crossarm type feeders using a normal, large conductor (about 600 MCM per phase) at a medium distribution primary voltage (e.g., 12.47 kV) costs about $150,000/mile. However, cost can vary greatly due to variations in labor, filing and permit costs among utilities, as well as differences in design standards, and terrain. Where a thick base of of topsoil is present, a pole can be installed by simply auguring a hole for the pole. In areas where there is rock close under the surface, holes have to be jack hammered or blasted, and costs go up accordingly. It is generally less expensive to build feeders in rural areas than in suburban or urban areas. Thus, while $150,000 is a good average cost, a mile of of new feeder construction could cost as little as $55,000 in some Situations situations and as much as $500,000 $500,000 in others. A typical distribution feeder (three-phase, (three-phase, 12.47 kV, 600 MCMlphase) MCM/phase) would be rated at a thermal (maximum) capacity of A and a of about 15 15 MV MVA recommended economic (design) peak loading of of about 8.5 MVA peak, depending on losses and other costs. At $150,000/mile, this capacity rating gives somewhere between $10 to $15 per kW-mile as the cost for basic distribution line. Underground construction of of a three-phase primary feeder is more expensive, requiring buried ductwork and cable, and usually works out to a range of$30 of $30 to $50 per kW-mile. kW-mile. Lateral lines, short primary-voltage lines working off off the main three-phase circuit, are often often single or two-phase and consequently have lower costs but lower capacities. Generally, they are about $5 to $15 per kW-mile overhead, with underground costs of W-mile (direct buried) to $30 of between $5 to $15 per kkW-mile to $100 per kW-mile (ducted). Cost of regulators, capacitor banks of other distribution equipment, including regulators, and their switches, sectionalizers, line switches, etc., varies greatly depending on the specifics of of each application. In general, the cost of of the distribution system will vary from between $10 and $30 per kW-mile.

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Service Level Costs

The service or secondary secondary system consists of of the service transformers that convert primary voltage to utilization voltage, the secondary secondary circuits that operate at utilization voltage and the service drops that feed power directly to each consumer. Without exception these are very local facilities, meant to move power no more than a few hundred feet at the very most and deliver it to the consumer "ready to use." use." Many electric utilities utilities develop cost estimates for this equipment on a perA poleconsumer basis. A typical service configuration might involve a 50 MY MVA mounted service transformer feeding ten homes, as shown in Figure 2.8. Costs for this equipment might include: Heavier pole & hardware for transformer application 50 kW transformer, mounting equipment, and installation 500 feet secondary (120/240 volt) single-phase @ $2/ft. 10 service drops including installation installation at $100

$250 $750 $1,000 $1,000 $3,000

A cost of about $300 per consumer, or about $60/kW of coincident load.

secondary

lateral (primary)

\

customer customer

service transformer

primary-voltage lateral, Figure 2.8 Here, a service transformer, transformer, fed from a distribution primary-voltage feeds in tum turn ten homes through through secondary circuit operating at utilization voltage.

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Maintenance and Operating Costs Maintenance Once put into service, T &D equipment must be maintained in sound, operating T&D operating condition, hopefully in the manner intended and recommended by the manufacturer. This will require periodic inspection and service, and may require repair due to damage from storms or other contingencies. In addition, &D facilities are like any many utilities utilities must pay taxes or fees for equipment (T (T&D other business property). Operating, maintenance, and taxes are a continuing annual expense. expense. difficult to give any generalization of of O&M&T costs, partly It is very difficult because they vary so greatly from one utility to another, but mostly because utilities account for and report them in very different different ways. Frankly, the authors have never been able to gather a large number of of comparable data sets from which to produce even a qualitative estimate of of average O&M&T costs.8 With that caveat, a general rule of of thumb: O&M&T costs for a power delivery system probably run between 1/8 1/8 and 1/30 of of the capital cost, annually.

Build The Cost to Upgrade Exceeds the Cost to Build of the fundamental factors affecting affecting design of of T&D One of T&D systems is that it costs more to upgrade equipment to a higher capacity than to build to that capacity in the original construction. For example, a 12.47 kV overhead, three-phase feeder with a 9 MW capacity (336 MCM phase conductor) might cost $120,OOO/mile $120,000/mile to build ($13.33 per kW-mile). Building it with 600 MCM conductor instead, for a capacity of 15 MVA, would cost in the neighborhood neighborhood of $150,000 ($IOIkW($10/kWmile). However, upgrading an existing 336 MCM, 9 MW capacity line to 600 MCM, 15 15 MVA capacity could cost $200,000/mile - over $30 per kW-mile for of additional capacity. This is more expensive because it entails the 6 MW of removing the old conductor and installing new conductor along with brackets, cross-arms, and other hardware required supporting the heavier new conductor. Typically, this work is done hot (i.e., with the feeder energized), which means

8 8

For example, some utilities include part of O&M expenses in overhead costs, others do not. A few report all repairs (including storm damage) as part of of O&M, others others accumulate repair work separately. accumulate major repair separately. Still others report certain parts of of routine service service (periodic rebuilding rebuilding of of breakers) as a type of of capital cost because it extends extends equipment life or augments augments capacity. Others report all such work as O&M, O&M, even when the rebuilding upgrades upgrades capacity capacity or voltage class.

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the work must be undertaken undertaken with extreme care and following a number of safety-related safety-related restrictions on equipment and labor. Thus, T&D T&D planners have an incentive to look at their long-term needs carefully, and to "overbuild" against initial requirements if if growth trends show of doing so must be weighed against future demand will be higher. The cost of long-term savings, but often T&D T&D facilities are built with considerable margin (50%) above existing load to allow for future load growth. The very high cost per kW for upgrading a T &D system in place creates one T&D of of the best-perceived opportunities for DSM and DG reduction. reduction. Note that the capital costlkW cost/kW for the upgrade capacity in the example above ($33/kW) is nearly three times the cost of of similar new capacity. Thus, planners often look at of the system where slow; continuing load growth has increased load to areas of the point that local delivery facilities are considerably taxed, as areas where DSM and DG can deliver significant savings. In some cases, distributed resources can reduce or defer significantly the T&D of the type described above. However, this does not need for T &D upgrades of assure significant savings for the situation is more complicated than an analysis of indicate. If the existing system (e.g., the 9 MW of capital costs to upgrade may indicate. feeder) needs to be upgraded, then it is without a doubt highly loaded, which means its losses may be high, even off-peak. The upgrade to a 600 MCM conductor will cut losses 8,760 hours per year. Financial losses may drop by a justifY the cost of significant amount, enough in many cases to justify of the upgrade upgrade alone. The higher the annual load factor in an area, the more likely this is to occur, but it is often the case even when load factor is only 40%. However, DSM and in some cases DG also lowers losses, making the comparison quite involved, as will be discussed later in this book. Electrical Electrical Losses Costs

Movement of of power through any electrical device, be it a conductor, conductor, transformer, regulator or whatever, incurs a certain amount of of electrical loss due to the impedance impedance (resistance (resistance to the flow of electricity) electricity) of the device. These losses are a result of of inviolable laws of of nature. They can be measured, assessed, assessed, and minimized minimized through proper engineering, but never eliminated completely. Losses are an operating operating cost

Although losses do create a cost (sometimes (sometimes a considerable one) it is not always desirable to reduce them as much as possible. Perhaps the best way to put them of T &D equipment as powered by electricity in proper perspective is to think of T&D electricity the system that moves power from one location to another runs on electric

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energy itself. Seen in this light, losses are revealed as what they are - a necessary operating expense to be controlled and balanced against other costs. necessary Consider a municipal water department, which uses electric energy to power the pumps that drive the water through the pipes to its consumers. Electricity is an acknowledged operating cost, one accounted for in planning, and weighed carefully carefully in designing the system and estimating its costs. The water department could choose to buy highly efficient efficient pump motors. Motors that command a premium price over standard designs but provide a savings in reduced electric power costs, and use piping that is coated with a friction-reducing lining to of water (thus carrying more water with less pump power), promote rapid flow of all toward reducing its electric energy cost. Alternatively, after weighing the cost of of this premium equipment against the energy cost savings it provides, the water department may decide to use inexpensive motors and piping and simply pay more over the long run. The point is that the electric power required to move the water is viewed merely as one more cost that had to be included in determining the lowest "overall" cost. It takes power to move power. Since its own delivery product powers electric delivery equipment, this point job of often is lost. However, in order to do its job of delivering electricity, a T&D system must be provided with power itself, just like the water distribution system. Energy must be expended to move the product. Thus, a transformer of the power fed into it. In order to move power 50 consumes a small portion of miles, a 138 138 kV transmission line similarly consumes a small part of of the power given to it. Initial cost of of equipment can always be traded against long-term financial efficient transformers can be purchased losses. Highly efficient purchased to use considerably less power to perform their function than standard designs. Larger conductors can be used in any transmission or distribution line, which will lower impedance, and thus losses for any level of of power delivery. But both examples here cost more money initially - the efficient efficient transformer may cost three times what a standard design does. The larger conductor might entail a need for not only large wire, but also heavier hardware to hold it in place, and stronger towers and poles to keep it in the air. In addition, these changes may produce other costs for example, use of of a larger conductor not only lowers losses, but a higher fault duty (short circuit current), which increases the required rating and cost for circuit breakers. Regardless, initial equipment costs can be balanced against of needs, performance, and long-term financial losses through careful study of costs, to establish a minimum overall (present worth) worth.

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Chapter 2

Load-related Load-related losses

Flow of of electric power through any device is accompanied by what are called load-related losses, which increase as the power flow (load) increases. These are due to the impedance of of the conductor or device. Losses increase as the square of the load - doubling the power flowing through a device quadruples the losses. of Tripling power flow increases the losses by nine. With very few exceptions, larger electrical equipment always has lower impedance, and thus lower load-related losses, for any given level of of power delivery. Hence, if if the losses inherent in delivering delivering 5 MW using a 600 MCM conductor are unacceptably large, the use of of a 900 MCM conductor will reduce them considerably. The cost of the larger conductor can be weighed against the savings in reduced losses to decide if it is a sound economic decision. No-load No-load losses

"Wound" T &D equipment - transformers and regulators - have load-related T&D losses as do transmission lines and feeders but in addition, they have a type of of electrical loss that is constant, regardless of of loading. No-load losses constitute the electric power required to establish a magnetic field inside these units, without which they would not function. Regardless of of whether a transformer has any load - any power passing through it at all - it will consume a small amount of of power, generally less than 1I % % of of its itsrated rated full full power, power, simply simplybecause because it is energized and "ready to work." No-load losses are constant, and occur 8,760 hours per year. Given similar designs, a transformer will have no load losses proportional to its capacity. A 10 MVA substation transformer will have twice the no-load A transformer of losses of of a 5 MV MVA of similar voltage class and design type. Therefore, unlike the situation with a conductor, selection of of a larger transformer does not always reduce net transformer losses, because while the larger transformer will always have lower load-related losses, it will have higher no-load losses, and this increase might outweigh the reduction in load-related losses. Again, low-loss transformers are available, but cost more than standard Lower-cost-than-standard but higher-loss transformers are also available types. Lower-cost-than-standard (often a good investment for backup and non-continuous use applications).

of losses The costs of T&D system - the electrical losses - is The electric power required to operate the T&D typically viewed as having two costs, demand and energy. Demand cost is the &D cost of of providing the peak capacity to generate and deliver power to the T T&D equipment. A T&D T&D system that delivers 1,250 MW at peak might have losses

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during this peak of of 100 100 MW. This means the utility must have generation, or buy power at peak to satisfY satisfy this demand, whose cost is calculated using the utility's power production cost at time of of peak load This is usually considerably above its average power production cost. &0 portion of Demand cost also ought to include a considerable T T&D of expense. Every service transformer in the system (and there are many) is consuming a job at peak. Cumulatively, this might equal small amount of power in doing its job 25 MW of of power - up to 114 1/4 of of all losses in the system. That power must not only be generated by the utility but also transmitted over its transmission system, through its substations, and along its feeders to reach the service transformers. Similarly, Similarly, the power for electrical losses in the secondary and service drops (while small, are numerous and low voltage, so that their cumulative contribution to losses is noticeable) has to be moved even farther, through the service transformers and down to the secondary level. of the capacity to provide the losses Demand cost of losses is the total cost of of consumption. and move them to their points of Energy losses occur whenever the power system is in operation, which generally means 8,760 hours per year. While losses vary as the square of load, so they drop by a considerable margin off-peak. Their steady requirement every hour of of the year imposes a considerable energy demand over the course of a year. This cost is the cost of of the energy to power the losses. Example: Consider a typical 12.47 kV, three-phase, OH feeder, feeder, with 15 MW capacity (600 MCM phase conductor), serving a load of of 10 10 MW at peak with 4.5% primary-level losses at peak (450 kW losses at peak), and having a load factor of of 64% annually. Given a levelized capacity cost of of power delivered of a substation of of $IOIkW, $10/kW, the demand cost of of these losses is to the low side bus of $4,500/year. Annual energy cost, at 3.5¢ IkWhr, can be estimated as: 3.50 /kWhr, 450 kW losses at peak x 8,760 hours x (64% load factor)2 factor)2 x 3.5¢ 3.50 == $56,500 Thus, the financial losses (demand plus energy costs) for this feeder are nearly $60,000 annually. At a present worth discount factor of of around 11 %, this means losses have an estimated present worth of of about $500,000. This computation used a simplification - squaring the load factor to estimate load factor impact on losses - which tends to underestimate losses slightly. Actual If the losses probably would be more in the neighborhood of of $565,000 PW. If peak load on this feeder were run up to its maximum rating (about 15 15 MW of 10 MW) with a similar load factor of of 64%, annual losses and their instead of 2 cost would increase to (15/1 0)2 or $1,250,000 dollars. (15/10) This feeder, feeder, in its entirety, might include four miles of of primary trunk (at $150,000/mile) and thirty miles of of laterals (at $50,000/mile), for a total capital

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cost of of about $2,100,000. Thus, total losses are on the order and magnitude magnitude of of original cost of of the feeder feeder itself, original itself, and in cases where loading is high, can approach of the approach that cost. Similar loss-capital relations exist for all other levels of T&D system, with the ratio of T&D of losses capital cost increasing increasing as one nears the consumer consumer level (lower voltage equipment equipment has higher 10sses/kW). losses/kW).

Costs Total T&D Costs What is the total cost to deliver electric power? Of Of course this varies from system to system as well as from one part of of a system to another - some service than others (Figure (Figure 2.9). consumers are easier to reach with electric service Table 2.2 shows the cost of residential of providing service to a "typical" residential consumer. 2.7 OF DELIVERY SYSTEM SYSTEM DESIGN DESIGN 2.7 TYPES OF There are three fundamentally layout fundamentally different different ways to lay out a power distribution system used by electric electric utilities, each of of which has variations design. variations in its own design. system As shown in Figure 2.10, radial, loop, and network systems differ differ in how the distribution feeders are arranged and interconnected about a substation. Most power distribution systems are designed as radial distribution distribution systems. systems. The radial system is characterized characterized by having only one path between each consumer and a substation. The electrical electrical power flows exclusively away from from path, which, if interrupted, the substation and out to the consumer along a single path, of power power to the consumer. results in complete complete loss of consumer. Radial design is by far the most widely used form of of distribution design, accounting for over ninety-nine

Providing Service to Typical Residential Residential Consumers Table 2.2 Cost Cost of of Providing

Level

Cost Components Cost

Cost Cost

Transmission

4 kW x 100 miles miles x $.75/kW mile 4 kW x $60/kW $60/kW

$300

Substation

Feeder Service

$1O/kW-mile 4 kW x 1.5 1.5 miles miles x $10/kW-mile l/10th of of 50 kVA local service system Ill0th Total Initial cost cost (Capital)

$240

$60 $300 $900

Operations, Maintenance, and Taxes (PW next 30 years) = $500

Cost of of electrical losses (PW next 30 years) == $700 I 00 Estimated cost of of power delivery, delivery, 30 years, PW $2, $2,100

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Power Delivery Systems

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N

1 10 mil.s T&D COST AYG.$166

1990

Shading indicates 10ad dens;t'1

IIIWater -Hi way

-Road

of power delivery varies depending on location. Shown here are the Figure 2.9 Cost of of delivery evaluated on a ten-acre basis throughout throughout a coastal city annual capacity capacity costs of of population 250,000. Cost varies from a low of$85/kW of $85/kW to a high of$270/kW. of $270/kW. of

of all distribution construction in North America. Its predominance is percent of due to two overwhelming advantages: it is much less costly than the other two alternatives and it is much simpler in planning, design, and operation. In most radial plans, both the feeder and the secondary secondary systems are designed and operated radially. radially. Each radial feeder serves a definite service area (all consumers in that area is provided power by only that feeder). Most radial feeder systems are built as networks, but operate radially by opening switches at certain points throughout the physical network (shown earlier in Figure 2.6), so that the resulting configuration is electrically radial. The planner determines the layout of of the network and the size of of each feeder segment in that network and decides where the open points should be for proper operation as a set of of radial feeders.

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Chapter 2

t

t

t

t

Radial

Loop

t

Network Network

Simplified illustration of of the concepts concepts behind three types of Figure 2.10 Simplified of power distribution configuration. Radial systems have only one electrical path from the substation to the consumer, loop systems have two, and networks have several. Arrows of electric flows. show most likely direction of

A further attribute of of most radial feeder system designs, but not an absolutely of single-phase single-phase laterals. Throughout Throughout North America, America, critical element, is the use of most utilities use single- and two-phase laterals to deliver power over short off only one or two phases of of the primary feeder. This distances, tapping off of wire that need be strung for the short segment minimizes the amount of segment required of a dozen or so consumers. to get the power power in the general vicinity of consumers. These laterals are also radial, but seldom, if ever, end in a switch (they just end). There are many utilities, particularly urban systems in Europe, Africa, and Asia of the radial distribution system, including laterals, with all that build every part of three phases. power into a small radial Each service transformer transformer in these systems feeds power system around it, basically a single electrical path from each service transformer to the consumers consumers nearby. Regardless Regardless of of whether it uses single-phase single-phase laterals or not, the biggest advantages of the radial system configuration, in addition to its lower cost, is the advantages of of performance. Because Because there is only simplicity of of analysis and predictability of between each consumer consumer and the substation, the direction of of power flow one path between of the system is absolutely certain. Equally important, the load on any element of system can be determined in the most straightforward straightforward manner - by simply adding up the entire consumer consumer loads "downstream" from that piece of of equipment. Before the advent of of economical and widely available computer analysis, analysis, this alone was an overwhelming advantage, for it allowed simple, simple, straightforward, "back of of the envelope" envelope" design procedures procedures to be applied to the straightforward, distribution system with confidence that the resulting system would work well.

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The simplicity of of analysis, and confidence that operating behavior is strictly predictable are still great advantages. advantages. Because load and power flow direction are easy to establish, voltage profiles can be determined with a good degree of of accuracy accuracy without resorting to exotic calculation methods. Equipment capacity requirements can be ascertained of accuracy; and exactly: fault levels can be predicted with a reasonable degree of protective devices - breaker-relays and fuses - can be coordinated in an absolutely assured manner, without resorting to network methods of of analysis. Regulators and capacitors can be sized, located, and set using relatively simple procedures (simple compared to those required for similar applications to nonradial designs in which the power flow direction is not a given). On the debit side, radial feeder systems are less reliable than loop or network systems because there is only one path between the substation and the consumer. Thus, if if any element along this path fails, a loss of of power delivery results. Generally, when such a failure occurs, a repair crew is dispatched to reswitch temporarily the radial pattern network, transferring the interrupted consumers onto another feeder, until the damaged element can be repaired. This minimizes the period of outage, but an outage still occurred because of of the failure. Despite this apparent flaw, radial distribution systems, if well designed and of reliability. constructed, generally provide very high levels of reliability. For all but the most densely populated areas, or absolutely critical loads (hospitals, important municipal facilities, the utility's own control center) the additional cost of of an inherently more reliable configuration (loop or network) cannot possibly be justified for the slight improvement that is gained over a well-designed radial justified system. An alternative to purely radial feeder design is a loop system consisting of a distribution design with two paths between the power sources (substations, service transformers) and every consumer. Such systems are often called of many "European," because this configuration is the preferred design of utilities, as well as European electrical contractors when called upon European utilities, to layout lay out a power distribution system anywhere in the world. Equipment is of sized and each loop is designed so that service can be maintained regardless of where an open point might be on the loop. Because of of this requirement, whether operated radially (with one open point in each loop), or with closed loops, the basic equipment capacity requirements of of the loop feeder design do not change. Some urban areas in Europe and Asia are fed by multiple hierarchical loop systems. A 100+kV IOO+kV sub-transmission sub-transmission loop routes power to several substations, out of power to service transformers, of which several loop feeders distribute power which each route powers through a long loop secondary.

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Chapter 2

In terms of of complexity, a loop feeder system is only slightly more complicated than a radial system. Power usually flows out from both sides of two routes. Voltage toward the middle, and in all cases can take only one of drop, sizing, and protection engineering are only slightly more complicated than for radial systems. if designed thus, and if But if if the protection (relay-breakers and sectionalizers) is also built to proper design standards, the loop system is more reliable than radial systems. Service will not be interrupted to the majority of of consumers consumers whenever a segment is outaged, because there is no "downstream" portion of any loop. The major disadvantage of of loop systems is capacity and cost. A loop must be able to meet all power and voltage drop requirements when fed from only one end, not both. It needs extra capacity on each end, and the conductor must be large enough to handle the power and voltage drop needs of of the entire feeder if fed from either end. This makes the loop system inherently more reliable than if a radial system, but the larger conductor and extra capacity increase costs. Distribution networks networks are the most complicated, the most reliable, and in of distributing distributing electric electric power. very rare cases also the most economical method of multiple paths between all points in the network. Power Power A network involves multiple flow between any two points is usually split among several paths, and if a failure occurs it instantly and automatically re-routes itself. Rarely does a distribution network involve primary voltage-level network design, in which all or most of of the switches between feeders are closed so that the feeder system is connected between substations. This is seldom done because it proves very expensive and often will not work well. wel1. 9 Instead, a "interlaced" radial feeders and a "distribution network" almost always involves "interlaced" network secondary of electrically electrically strong (i.e., larger than needed secondary system - a grid of to feed consumers in the immediate area) conductor connecting all the consumers together at utilization voltage. Most distribution networks are underground simply because they are employed only in high-density areas, where overhead overhead space is not available. In this type of of design, the secondary grid is fed from radial feeders through service transformers, basically the same way the secondary is fed in radial or loop systems. The feeders are radial, but laid out in an interlaced manner - none has a sole service area, but instead they overlap. The interlaced configuration

9 9

puts feeder network paths in parallel parallel with transmission The major reason is this puts transmission between substations, which results results in unacceptable loop and circular flows as well as large dynamic dynamic shifts in load on the distribution system.

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Power Delivery Systems

means that alternate service transformers along any street or circuit path are fed from alternate feeders, as shown in Figure 2.11. While segments from two feeders always run parallel in any part of of the system, the same two feeders never overlap for all of of their routing. The essence of the interlaced system (and a design difficulty of difficulty in any practical plan) is to mix if partially parallels a few other feeders. Thus, if up feeders so that each feeder partially the feeder fails, it spreads its load out over a few other feeders, overloading none severely (Figure 2.12). At a minimum, minimum, distribution networks use an interlacing factor of of two, meaning that two feeders overlap in anyone any one region, each feeding every other service transformer. But such a system will fail when any two feeders are out of of service. Interlacing factors as high as five (four overlapping feeders, each feeding every fourth consecutive service transformer) have been built. Such systems can tolerate the loss of of any three feeders (the other two in any area picking up the remaining load, although often often very overloaded) without any power flow in the interruption of of consumer service. If If an element fails, the power elements around it merely re-distributes itself slightly.

service transformers •~

Feeder A Feeder B

1

19 —£ 9 in:yl T"

Figure 2.11 To obtain an interlacing factor of of 2, two feeders are routed down each street, with alternating alternating network transformers transformers fed from each.

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76

Chapter 2 NORMAL

1 IP g—- !NORMAL

FEEDER #2 FAILED

CU

D—FEEDER #2 FAILED

Figure 2.12 Top: a non-interlaced of one feeder, non-interlaced feeder system experiences the loss of feeder, and all transformers transformers in the lower right part of of the system are lost - service is certain to be interrupted. Bottom: the same system interlaced. Loss of of the feeder is a serious contingency, but can be withstood because the feeder losses are distributed in such a way that transformers still in service surround each transformer out of of service.

Networks are more expensive than radial distribution systems, but not greatly so in some instances. In dense urban applications, where the load density is very high, where the distribution must be placed underground, and where repairs and maintenance are difficult traffic and congestion, difficult because of of traffic networks may cost little more than loop systems. Networks require only a little more conductor capacity than a loop system. The loop configuration required "double capacity" everywhere to provide increased reliability. A distribution network is generally no worse and often needs considerably less maintenance than if built to a clever design. Networks have one major disadvantage. They are much more complicated, than other forms of of distribution, and thus much more difficult difficult to analyze. There There is no "downstream" side to each unit of of equipment in a radial or loop system, so that the load seen by any unit of of equipment cannot be obtained by merely adding up consumers on one side of of it, nor can the direction of of power flow through it be assumed. Loadings and power flow, fault currents and protection through protection must be determined determined by network techniques such as those used by transmission planners. However, even more sophisticated sophisticated calculation methods than those applied to transmission may be required, because because a large distribution network can consist of of 50,000 nodes or more - the size of the very largest transmission-

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Power Delivery Systems

level power pool. Distribution network load flows are often more difficult difficult to solve than transmission transmission systems because the range of impedance impedance in the modeled of magnitude wider. circuits is an order of In densely populated regions, such as the center of of a large metropolitan area, networks are not inherently more expensive than radial systems designed to serve the same loads. Such concentrated load densities require a very large number of of circuits anyway, so that their arrangement in a network does not inherently increase the number of of feeder and secondary circuits, or their of the design. capacity requirements. It increases only the complexity of But in other areas, such as in most cities and towns, and in all rural areas, a network configuration will call for some increase (in kVA-feet of of installed conductor) over that required for a radial or loop design. The excess capacity of reliability. cost has to be justifiable on the basis of Feeder Layout Large-Trunk vs. Multi-Branch Feeder Figure 2.13 illustrates the basic concept behind two different different ways to approach Each has advantages and the layout of of a radial distribution system. disadvantages with respect to the other in certain situations, and neither is of reliability, cost, ease of of protection, and service superior to the other in terms of quality. Either can be engineered to work in nearly any situation. Most planning utilities have an institutionalized preference for one or the other. Beyond showing that there are significantly different different ways to layout a distribution system, this brings to light an important point about distribution differences in standards exist among electric utilities, as a result design: major differences of which comparison of of statistics or practice from one to the other is often often not of valid. Feeder layout types and practices are discussed in much greater detail in Chapters 8 and 9 of the Power Distribution Planning Reference Reference Book. Book.

minimi minim

D

108 service transformers. transformers. Left, a Figure 2.13 Two ways to route a radial feeder to 108 "multi-branch" configuration. Right, a "large trunk" design.

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78

Chapter 2

Service Areas

As mentioned earlier, in most power systems, each substation is usually the sole provider of of electrical service to the region around it - its service area. Similarly, feeders and distribution distribution networks also have distinct service areas. Usually, the service area for a substation, feeder, or other unit of of equipment is the immediate area surrounding it, and usually these service areas are contiguous (i.e. not broken into several parts) and exclusive - no other similar distribution unit of the load in an area. As an example, Figure 2.14 shows a map of of serves any of of a power system. Each substation service areas for a rectangular portion of distribution substation exclusively serves all consumers in the area containing it. Cumulatively, the consumers in a substation or feeder's feeder's service territory determine its load, and their simultaneous peak demand defines the maximum individual part, power the substation must serve. Within a power system, each individual such as a substation or service transformer, will see its peak load at whatever season the consumers in its service area generate their time and in whatever season of this is that the peak loads for different cumulative peak demand. One result of different substations often occur at different of the day. But different seasons of of the year or hours of whenever the peak occurs, it defines defines the maximum power the unit is required to deliver. Peak demand is one of of the most important criteria in designing and planning distribution systems. Usually it defines the required equipment equipment capacity.

N

Ten Miles

Figure 2.14 A power system is divided by substation service boundaries boundaries into a set of of substation service areas, as shown.

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79

Dynamic Service Area Planning Planning

By making switching changes in the distribution system, it is possible to expand or shrink a substation or feeder's service area significantly, increasing or decreasing its net load. This is an important element of of T T&D planning, as &D planning, shown in Figure 2.15, which illustrates a very typical T &D expansion situation. T&D Two neighboring substations, A and B, each have a peak load near the upper load-handling range. Load is growing throughout growing slowly throughout limit of their reliable load-handling the system, so that in each substation annual peak load is increasing at about 1 MW per year. Under present conditions, both will need to be upgraded soon. Approved transformer types, required to add capacity to each, are available only $500,000 or more. in 25 MVA MV A or larger increments, costing $500,000 Both substations do not need to be reinforced. reinforced. A new 25 MV A transformer MVA associated equipment are added to substation A, increasing its ability to and associated handle a peak load by about 20 MVA. Ten MW of of substation substation B's B's service area 10 MW of is then transferred to A. The result is that each substation has 10 of margin for continued load growth - further additions are not needed for 10 years.

Before Before

After

_ W.n.llmed transferred load

Figure 2.15 2.15 Load in both substations is growing at about 1 MW per year. Each substation has sufficient capacity to handle present load within contingency criteria (a 25% margin transferring load as shown above, only margin above peak) but nothing more. By transferring one substation has to be reinforced reinforced with an additional (25 MVA) MVA) capacity, yet both end up with sufficient margin for another ten years' growth. Service area shifts keep expansion costs down in spite of transformers are available of the fact that equipment equipment like transformers available only in large, discrete sizes.

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This type of of planned variation in service areas is a major tool used to keep T&D expansion costs low, a key element in building a reliable, economical particular aspect of schedule of of expansion. Optimization of of this particular of planning can be a chaJlenge, challenge, not because of any inherent difficulty difficulty in analysis, but simply because there are so many parts of the system and constraints to track at one time. This is one reason for the high degree of of computerization in distribution planning at many utilities. of many utilities. Balancing the myriad requirements of substations and their design and operating constraints is an ideal problem for substations numerical numerical optimization optimization techniques. Approach The Systems Approach One complication in determining the most economical equipment for a power system is that its various levels - transmission, substation, and distribution - are interconnected, with the distribution in tum, turn, connected connected to the consumers and hence a function of of the local load density. The best size and equipment type at of the types of of equipment selected for the each level of of the system is a function of of the system and the load density. In general, the equipment is so other levels of interconnected that it is impossible to evaluate anyone any one aspect of of design without taking all others into account. Consider the question of of substation spacing - determining how far apart substations should be, on average for best utilization and economy. Within any of service territory, if substations are located farther apart, there will be fewer of them, saving the utility the cost of buying and preparing some substation sites, of substations. Thus, of building a large number of as well as reducing the cost of overall substation of spacing, but how it varies depends on substation cost is a function of land and equipment costs, which must be balanced carefully. With fewer substation must serve a larger area of of the system. substations however, each substation Hence, each substation will have a larger load and thus require a larger capacity, meaning it must have more or larger transformers. of power to be The larger substations will also require a larger amount of brought to each one, which generally calls for a higher sub-transmission voltage. Yet there will be fewer sub-transmission lines required because there are fewer substations to which power must be delivered. All three aspects of of layout are related - greater substation spacing calls for larger substations with bigger transformers, and a higher transmission voltage, but fewer lines are needed - and all three create better economies of of scale as spacing is increased. increased. Thus, transmission costs generally drop as substation spacing is increased. Nevertheless, there is a limit to this economy. The distribution feeder system is required to distribute each substation's power through its service area, moving power out to the boundary between each substation's service area and that of of its

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neighbors. Moving substations farther apart means that the distribution system must move power, on average, a greater greater distance. Distributing power over these longer distances requires longer and more heavily loaded feeders. This situation increases increases voltage drop and can produce higher losses, all of which can increase cost considerably. Employing a higher distribution voltage (such as 23.9 kV instead of 13.8 kV) improves performance and economy, but it costs more to distribute power from a few larger substations farther apart, than to distribute it from many smaller substations close together. Feeder costs go up rapidly as increased. substation spacing is increased. The major point of this section is that all four of the above aspects aspects of system design are interconnected 1) substation spacing in the system, 2) size and design interconnected - 1) number of substations, 3) transmission voltage and design and, 4) distribution feeder voltage and design. One of these factors cannot be optimized without Therefore, close evaluation of its interrelationship with the other three. Therefore, determining the most cost-effective design guideline involves evaluating the transmission-substation-feeder transmission-substation-feeder system design as a whole against the load pattern, and selecting the best combination of transmission voltage, substation transformer sizes, substation spacing, and feeder system voltage and layout. This economic determination is based based on economic equipment sizing and layout determination achieving a balance between between two conflicting cost relationships: 1. 1.

Higher voltage equipment is nearly always more economical economical on a per-MW basis.

2.

of Higher voltage equipment is available only in large sizes (lots of MW).

In cases where the local area demands are modest, higher voltage equipment may be more expensive simply because the minimum size is far above what is required - the utility has to buy more than it needs. How these two cost relationships play against one another depends on the load and the distances over which power must be delivered. Other factors to be considered considered are those unique to each power system, such as the voltages at which power is delivered from the regional power pool, and whether the system is underground or overhead. Figure 2.16 illustrates the difference that careful coordination coordination of system power system can have in lowering overall overall cost. design between levels of the power &D system layout Shown are the overall costs from various combinations of a T T&D for a large metropolitan utility in the eastern United States. Each line connects a set of cost computations for a system built with the same transmission and

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distribution voltages (e.g., 161 kV transmission and 13.8 kV distribution) but implicitly, their spacing). varying in substation sizes (and hence, implicitly, In all cases, the utility had determined it would build each substation with two equally sized transformers (for reliability), reliability), with none over 75 MVA (larger transformers are too difficult difficult to move along normal roads and streets, even on special trailers). Either 161 trailers). Either 161 kV or 69 kV could be used as sub-transmission, either 23.9 kV or 13.8 kV could be used as distribution voltage. Any size 15 MV MVA transformer, from IS A to 75 MVA MV A could be used, meaning the substation could vary from 30 MV A to ISO MV A in size. (Peak load of MVA 150 MVA of such substations can normally be up to 75% of of capacity, for a peak load of of from 23 to 100 MW). Substation spacing itself is implicit and not shown. Given the requirement to cover the system, determining transmission voltage, distribution, distribution, and substation size defines the system design guidelines entirely. entirely. Overall, the ultimate ultimate and lowest cost T&D system guidelines are to build 120 MV A substations (two 60 MV A transformers) fed by 161 kV k V sub-transmission MVA MVA and distributing distributing power at 23.9 kV. This has a levelized cost (as computed for of about $179/kW. In this particular case, a high distribution this utility) utility) of voltage is perhaps the most important key to good economy - if if 13.8 kV is used instead of 23.9 kV as the primary voltage, minimum achievable cost rises to $193/kW. The very worst design choices plotted in Figure 2.16, from an economic standpoint, would be to build 25 MVA MV A substations fed by 161 161 kV subtransmission and feeding power to 23.9 kV feeders ($292/kW). This would require many small substations, each below the effective effective size of of both the transmission and distribution voltages, and lead to high costs. Overall, 161 kV and 23.9 kV are the correct choices for economy, but only if used in conjunction conjunction with a few, large substations. If If substations are to be 25 MVA, then 69 kV and 13.8 kV do a much more economical job job ($228/kW), but still don't achieve anything Achieving economy in power anything like the optimum optimum value. The point: Achieving delivery involves interactions, performance, and economies of involves coordinating the interactions, of the multiple system levels. II and 12 discuss the issues of of and levels. Chapters 11 techniques for such coordinated multi-level planning. planning.

2.8 CONCLUSION A transmission and distribution distribution system moves power from a utility's power of production and purchase points to its consumers. The T&D system's mission of

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Power Delivery Systems

83

300

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ca

§~ ...J ~

0( LU W D.. QL

23.9k~

....oo

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SUBSTATION CAPACITY - MVA

2.16 Overall cost of of T T&D balanced design of of the subFigure 2.16 &D system depends on the balanced subtransmission, substation, and feeder level, level, as described in the text. Cost can vary by significant margins depending on how well performance and economy economy at various levels of the system are coordinated. coordinated.

delivering power to the consumers of consumers means that it must be composed of equipment spread throughout the service territory and arranged arranged locally so that capacity is always in proportion to local electrical demand. The facilities need to be in each neighborhood, sized and configured both to fit well into the whole and to serve the local needs. In the authors' opinion, engineering engineering a system to meet this challenge is seldom easy, but engineering a system to do so at the minimum possible cost is always extremely challenging. A T&D T&D system is composed of of several interconnected, hierarchical levels, each of which is required for completion of the power delivery task. These are: levels are: I. Transmission 1. 2. Sub-transmission 3. Substation 4. Feeder 5. Secondary 6. Consumer

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84

Chapter 2

To a certain extent, the burden of power delivery, of power delivery, and costs, can be shifted of equipment, from one level to another through changes in the specifications of layout standards, and design of levels. For example, costs can be of the various levels. pared at the substation level by using fewer, larger substations. This means, means, feeders in each substation area will have to carry power power farther, and perhaps well, increasing feeder costs. Low overall carry more power power per feeder as well, design cost is achieved by balancing these factors. The performance and economy and thus the design, of of a power system are dominated by a number of of constraints constraints due to physical laws, and further shaped by a number of of practical considerations considerations with regard to equipment, layout, and operating requirements. requirements. The more important of these are:

1.

T&D Cover Ground. This is the rule about T&D The T &D System System Must Must Cover T &0 ultimately the electric system system must "run "run a wire" to every consumer. consumer. A significant portion of of the cost ofa of a distribution system is due to this requirement alone, independent of of the amount of of peak load or energy energy supplied.

2.

Interconnectivity of Levels. The sub-transmission/substation-feeder sub-transmission/substation-feeder Interconnectivity of triad comprises a highly interconnected interconnected system with the electrical and economic performance at one level heavily heavily dependent dependent on design, design, siting, and other decisions at another level. level. To a certain certain extent the T &0 system must be planned and designed as a whole - its parts T&D isolation. cannot be viewed in isolation.

3.

Equipment Sizes. Sizes. In many cases equipment is available Discrete Equipment only in certain discrete sizes. For example, 69 kV/12.47kV kY1l2.47kY transformers may be available only in 5, 10,20, 10, 20, and 22 MYA MVA sizes. Usually, there is a large economy economy of of scale - the installed installed cost of of a 20 MY A unit being considerably less than two times that for a 10 MY A MVA MVA unit.

4.

Powerful Planning Tool. Dynamic Service Area Assignment is a Powerful Tool. of equipment utilization of cost per Maximization of utilization and minimization of unit of of capacity can be obtained despite the fact that capacity capacity upgrades upgrades can be built only in one of of several discrete sizes. To accomplish this the planner changes changes the boundaries of of the service service area during the planning process. When reinforced with new surrounding capacity additions, a substation might pick up load from surrounding spreading the capacity addition among among substations, effectively spreading several substations.

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Power Delivery Systems 5.

Losses Cost Can Be Significant. In some cases, the present worth of of future losses on a line or heavily loaded transformer can exceed its total capital cost. In most cases, this does not happen. But in most cases, the present worth of of losses is greater than the difference in cost between most of of the choices available to the planner. This means loss is a major factor to be considered considered in achieving overall least-cost design.

6.

Cost to Upgrade Upgrade is Greater than the Cost to Build. For example, one mile of of a 12.47 kY, kV, three-phase feeder using 600 MCM conductor (15 MW thermal capacity) might cost $150,000 to build, build, and one mile of of 9 MW feeder (336 MCM conductor) might cost only $110,000. But the cost to upgrade the 336 MCM feeder to 600 MCM wire size at a later date would be about $130,000, for a cumulative total of of $240,000. Therefore, one aspect of of minimizing cost is to determine size for equipment not on the basis of of immediate need, but by assessing assessing the eventual need and determining whether the present worth of of the eventual savings warrants the investment in larger size now.

7.

Coincidence Coincidence of of Peaks. Not all consumer loads occur at the same time. This has a number of of effects. First, peak load in different different parts of different times. Second, the system peak of the system may occur at different load will always be less than the sum of of the peak loads at anyone any one of the system. For example, in more power systems the sum of of level of all substation peak loads usually exceeds system total peak by 3% to 8%. Diversity of peak loads means that considerable attention must be paid to the pattern and timing of of electric load if if equipment needs (and consequently costs) are to be minimized.

8.

Reliability is obtained Reliability obtained through Contingency Contingency Margin. Traditionally, T &D reliability reliability in a static system (one without automation, and T&D hence incapable of of recognizing and reacting to equipment outages and other contingencies by re-configuring and/or re-calibrating equipment) is assured by adding an emergency, or contingency margin throughout the system. At the T &D level this means that an T&D average of of 20% to 50% additional additional capacity is included in most if neighboring equipment, so that it can pick up additional load if equipment fails or is overloaded.

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85

86

Chapter 2

A Complicated System System

of an electric utility's In conclusion, a power power T&D system provides the delivery of consumer's site, with high product. It must deliver that product to every consumer's composed of of equipment equipment that is reliability and in ready-to-use form. While composed T&D individually straightforward, most T &D systems are quite complex due to the interactions of millions, of of thousands, even millions, of interconnected elements. Achieving Achieving economy and reliability reliability means carefully balancing a myriad of mutual economy interactions with conflicting conflicting cost tradeoffs. REFERENCES Fundamentals and Applications, Applications. Marcel J. J. J. Burke, Burke, Power Distribution Engineering - Fundamentals Dekker, New York, 1994.

al., editors, editors, Tutorial Tutorial on Distribution Planning, IEEE Course Text EHO M. V. Engel et aI., of Electrical and Electronics Engineers, Hoes Lane, NJ, 1992. 361-6-PWR, Institute of A.

Transmission and and Distribution C. Monteith and C. F. Wagner, Electrical Transmission Reference Electric Company, Pittsburgh, PA, 1964. Reference Book, Westinghouse Electric

H. L. Willis, Power Distribution Planning Reference Reference Book, Marcel Dekker, New York, 1997 1997

L. Willis and and W. W. O. G. Scott, Distributed Power Power Generation Generation - Planning and Evaluation, Evaluation, H. L. Marcel Dekker, New York, York, 2000

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3 Customer Demand for Power and Reliability of Service 3.1 3.1 THE TWO Qs: Qs: QUANTITY QUANTITY AND QUALITY OF POWER

Electric consumers require power, whether delivered delivered from the utility grid or generated locally by distributed sources, in order to help accomplish the uses for which they need energy. Their need for electric power, and the value they place fundamentally separate upon its delivery to them, has two interrelated but fundamentally dimensions. These are the two Qs: Quantity, the amount of power needed, and Quality, the most important aspect of which is usually dependability of supply (reliability of power supply, or availability as it is often called). The relative importance of these two features varies from one consumer to another depending on their individual needs, but each consumer consumer finds value in both the amount of power he obtains, and its availability as a constant, steady source that it will be there whenever needed. This chapter discusses demand and use of electric power as seen from the customer's standpoint: the utility's job job is to satisfy consumer needs as fully as possible within reasonable reasonable cost constraints. Cost is very much an important aspect to consumers too, so both the utility and the consumer must temper their plans and desires with respect to power power and reliability based on real world economics. Consumers do not get everything they want; only what they are willing to pay for. for. Utilities should not aim to provide flawless flawless service, which

87 Copyright © 2001 by Taylor & Francis Group, LLC

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Chapter 3

would be prohibitively expensive, but instead aim to provide the highest level willingness to pay. possible within economic constraints of the customers' willingness of This chapter begins, in section 3.2, with a discussion of consumer use of electricity and includes the quantity quantity of electric demand as seen from an "end"enduse" perspective. It continues with how demand varies as a function of of consumer type and end-use, and how power demand is represented in electric system studies using load curves and load duration curves. Section 3.3 then discusses reliability reliability and availability availability as seen by the customers and ways this can be characterized characterized and studied. Section Section 3.4 briefly reviews Two-Q analysis and planning concepts and their application to customer load analysis. analysis. Finally, section 3.5 provides a summary of key points. QUANTITY OF POWER POWER 3.2 ELECTRIC CONSUMER NEED FOR QUANTITY No consumer wants electric energy itself. itself. Consumers want the products products it can provide - a cool home in summer, hot water on demand, compressed compressed air for manufacturing, electronic robotic factory control, cold beer in the 'fridge and football on color TV. Electricity is only an intermediate means to some end-use. different goals and needs are called end-uses, and they span a wide These different range of applications. Some end-uses are unique to electric power (the authors are not aware of any manufacturer of natural natural gas powered TVs, stereos, or computers). For many other end-uses, electricity is only one of several possible energy sources (water heating, home heating, cooking, cooking, or clothes drying). In many other end-uses, electricity is so convenient that it enjoys a virtual gasoline-powered monopoly, even though there are alternatives, e.g., gasoline-powered refrigerators, and natural gas for interior lighting and for air conditioning. Each end-use is satisfied through the application of appliances or devices that desired end product. For example, with lighting a convert electricity into the desired wide range of illumination devices are used, including including incandescent incandescent bulbs, fluorescent tubes, sodium vapor, high-pressure monochromatic gas-discharge tubes, and in special cases, lasers. Each type of lighting device has differences from the others that give it an appeal to some consumers or for certain types of of applications. Regardless, each requires electric power to function, creating an electric load when it is activated. Similarly, Similarly, for other end-uses, such as space space electric heating, there are various types of appliances, each with advantages or reliability and maintenance, disadvantages in initial cost, operating efficiency, reliability noise and vibration, vibration, or other aspects. Each produces an electric load when used to produce heat for a home or business.

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Consumer Demand for Power and Reliability of Service

89

Other utilities - 9% 9% Industrial-11% Industrial - 11%

Commercial --22% 22%

Cooling - 50% Residential - 58% Lighting - 17% Water Heat -12% Cooklng-9% Refrig. -6% Other-6%

Figure 3.1 Electric peak demand of a utility in the southeastern United States broken down by consumer class and within the residential class, by contribution to peak for the major uses for which electricity is purchased at time of peak by the residential class.

Consumer Classes Consumer Different Different types of consumers purchase electricity. About half of all electric power is used in residences, which vary in the brands and types of appliances own, and their daily activity patterns. Another fourth fourth is consumed by they own, Commercial businesses both large and small, that buy electricity, having having some illumination), similar end-uses to residential consumers (heating and cooling, and illumination), unique to commercial functions functions (cash but that have many needs unique register/inventory systems, escalators, office office machinery, neon store display lighting, parking lot lighting). Finally, industrial facilities and plants buy electricity to power processes such as pulp heating, compressor and conveyor motor power, and a variety of manufacturing applications. As a result, the load on an electric system is a composite of many consumer types and appliance 3.1 shows this breakdown of the peak electrical electrical load for a applications. Figure 3.1 typical power system by consumer class and end-use category within one class.

Appliances Convert End Uses into Electric Electric Load The term load refers to the electrical demand of a device connected to and e.g., drawing power from the electric system in order to accomplish some task, e.g.,

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Chapter 3

energy, opening a garage door, or converting that power to some other form of energy, appliances, whether they are a such as a light. Such devices are called appliances, household item, e.g., a refrigerator, lamp, garage door commonly regarded regarded household paper shredder, electric fence to keep cattle confined, etc. To the opener, paper consumer, these appliances convert electricity into the end product. But the electric service planner can turn this relation around and view an appliance (e.g., a heat pump) as a device for transforming a demand for a particular end-use warm or cool air - into electric load. The level of power they need usually rates electrical electrical loads, measured in units of real volt-amperes, called watts. Large loads are measured measured in kilowatts watts). Power ratings of loads (thousands of of watts) or megawatts (millions of watts). T &D equipment refer to the device at a specific nominal and T&D nominal voltage. For example, an incandescent light bulb might be rated at 75 watts and 1,100 lumens at 120 volts, at which voltage it consumes 75 watts and produces 1,100 1,100 lumens of light. light. If provided with less voltage, its load (and probably its light output) will fall. Load Curves and Load Curve Curve Analysis

The electric electric load created created by anyone any one end-use usually varies as a function of time. For example, in most households, demand for lighting lighting is highest in the early evening, after after sunset but before most of the household members have gone to bed. Lighting needs may be greater on weekends, when activity activity often lasts later earlier in the day. into the evening, and at times of the year when the sun sets earlier Some end-uses are quite seasonal. Air-conditioning Air-conditioning demand generally occurs greatest during particularly hot periods and when family only in summer, being greatest activity is at its peak, usually usually late afternoon or very early evening. Figure 3.2 of shows how the demand for two products of electric power varies as a function of time. The result of this varying demand for the products of electricity application, is a variation in the demand for power as a function of time. This is plotted as a load curve, illustrated in Figure 3.3. Typically, the values of most interest to the planners are the peak load (maximum (maximum amount of power that must be delivered). This defines directly or indirectly, indirectly, the capacity requirements for equipment; the minimum load and the time it occurs; the total energy, area under the curve that must be delivered during the period being analyzed; analyzed; and the load value at the time of of system peak load. Consumer Class Load Curves

While all consumers within a consumers differ differ in their electrical electrical usage patterns, consumers within particular class, such as residential, tend to have broadly similar similar load curve patterns. Those Those of different different classes tend to be dissimilar in their demand for

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91

Consumer Demand for Power and Reliability of Service 25

25

I 20

20

| 15

15

cl 'S x ,92 10

.10 j I

5

OL-----------------------~ Mid Noon Mid Time of TIme 01 Day

OL^

Noon Time 01 of Day TIme

Mid

Mid

Figure 3.2 End-use demand. (Left) Average demand for BTU of cooling among houses Right, lighting in one of the authors' neighborhoods on a typical weekday in June. Right, lumens used by a retail store on a typical day in June.

Summer and Winter Residential Summer Residential Peak Day Load Curves Summer Summer

6



«

Winter Winter

«

>

~

>

0

0

~

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9

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Figure Figure 3.3 Electric demand for each class varies hourly and seasonally, as shown here, with a plot of average coincident coincident load for residential users in central Florida. Florida.

Residential

Commerical

Industrial 15

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~

Q

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g Time of Day

Time of Day

Time of Day

Figure Different consumer classes have different different electrical demand characteristics, Figure 3.4 Different particularly with regard to how demand varies with time. Here are summer peak day load curves for the three major major classes of consumer from the same utility system.

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92

Chapter 3

Q

O 100 50

~~2~~~~-L6-L~~~-No~o-n~~-L-L~6-L-L~~~12 12 Noon 12 Hour

Figure 3.5 Demand on all an hourly basis (blocks) over 24 hours, and the actual load curve (solid black line) for a feeder segment serving 53 homes. Demand measurement averages load over over each demand interval interval (in this case each hour) missing some of the detail of the actual load behavior. In this case the actual peak load (263 kW at 6 PM) was not seen by "split the peak," averaging load on an hourly basis and the demand measuring, which "split seeing a peak demand of only 246 kW, 7% lower. As will be discussed later in this chapter, an hourly hourly demand period is too lengthy lengthy for this application.

of day and year when their demand is both quality and quantity and the time of highest. Therefore, most electric utilities utilities distinguish distinguish load behavior on a classby-class basis, characterizing each class with a "typical daily load curve," curve," showing the average or expected pattern of load usage for a consumer in that class on the peak day, as shown in Figure 3.4. These "consumer "consumer class load curves" describe how the demand varies as a function of time. While often an entire 8,760-hour record for 8,760-hour record for the the year is available, usually only key key days -day per season - are for studies. perhaps one one representative day are used for The most important points concerning the consumers' loads from the distribution planner's standpoint are: 1. Peak demand demand and its time and duration 2. 3.

Demand at time of Demand of system peak Energy usage (total area under the annual load curve)

4.

duration Minimum demand, its time and duration

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Consumer Demand for Power and Reliability of Service

93

Details of Load Curve Measurement

Demand and demand periods "Demand," as normally used in electric load analysis and engineering, is the average value of electric load over a period of time known as the demand interval. Very often, demand is measured on an hourly basis as shown in Figure 3.5, but it can can be measured on any any interval basis - seven seconds, one one minute, 30 minutes, daily, and monthly. monthly. The average value of power during the demand interval is given by dividing kilowatt-hours accumulated during the demand dividing the kilowatt-hours interval by the length of the interval. Demand intervals vary among power companies, but those commonly used in collecting data and billing consumers for "peak demand" are 15, 15, 30, and 60 minutes. Load curves may be recorded, measured, or applied over some specific time. hourly For example, a load curve might cover one day. If recorded on an hourly demand basis, the curve consists of 24 values, each the average demand during one of the 24 hours in the day, and the peak demand is the maximum hourly demand seen in that day. Load data is gathered and used on a monthly basis and on an annual basis.

Load factor Load factor is the ratio of the average to the peak demand. The average load is the total energy used during the entire period (e.g., a day, a year) divided by the number of demand intervals in that period (e.g., 24 hours, 8,760 hours). The average is then divided by the maximum maximum demand to obtain the load factor: factor: Load Factor

kWhlHrs _ kWh/Hrs _ Average Demand kW =------- = Peak Demand kW Peak Demand kW =

KWh

(3.1)

(3.2)

(kW Demand) x (Hr)

Load factor gives the extent to which the peak load is maintained during the study. A high load factor means the load is at or near peak a good period under study. portion of the time. Load Duration Curves Curves

A convenient way to study load behavior is to order the demand samples from from greatest to smallest, rather than as a function of time, as in Figure 3.6. The two diagrams consist of the same 24 numbers, in a different different order. Peak load, minimum load, and energy (area under the curve) are the same for both.

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Chapter 3

Load duration curve behavior will vary as a function of of the level of of the of consumers will have a greater greater system. Load duration curves for small groups of ratio of of peak to minimum than similar curves for larger groups. Those for very small groups (e.g., one or two consumers) will have a pronounced "blockiness," consisting of plateaus - many hours of similar demand level (at least if the load data were sampled at a fast enough rate). The plateaus correspond correspond to combinations of major appliance loads. The ultimate "plateau" would be a load duration curve of of a single appliance, for example a water heater that operated operated a total of of 1,180 hours during during the year. This appliance's load duration curve would show 1,180 hours at its full load, and 7,580 hours at no load, without any values in between.

Annua//oad Annual load duration duration curves Most often, load duration curves are produced on an annual basis, reordering reordering all 8,760 hourly demands (or all 35,040 quarter quarter hour demands if using IS-minute 15-minute demand intervals) in the year from highest to lowest, to form a diagram diagram like that in Figure 3.7. The load shown was above 26 kW (demand minimum) 8,760 8,760 hours in the year, never above 92 kW, but above 40 kW for 2,800 hours. Spatial Patterns of Electric Demand

An electric utility must not only produce or obtain the power required by its consumers, but also must deliver it to their locations. Electric consumers consumers are scattered throughout the utility service territory, and thus the electric load can be thought of of as distributed on a spatial spatial basis as depicted in Figure 3.9. Just as load curves show how electric load varies as a function of of time, (and can help identify when certain amounts of of power must be provided), so has Spatial Load identifY Analysis been used since its development in the 1970s (Scott, 1972) to identifY identify where load is located and how much capacity is needed in each locality. The electric demand in an electric utility service territory varies as a function of of location depending on the number and types of of consumers in each locality, as shown by the load map in Figure 3.9. Load densities in the heart of of a large city square mile over can exceed I1 MW/acre, but usually average about 5 MW per square the entire metropolitan area. In sparsely populated rural areas, farmsteads can be as far as 30 miles apart, and load density as low as 75 watts per square mile. Regardless of of whether an area is urban, suburban, or rural, electric load is a of the types of of consumers, their number, their uses for electricity, and function of the appliances they employ. Other aspects of power system performance, performance, including capability, capability, cost, and reliability, can also be analyzed on a location-

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95

Consumer Demand for Power and Reliability of Service Hourly Load Curve Curve Hourly

Hour of the Day Hou'

Hour of the Day tb.r

reordered from Figure 3.6 The hourly demand samples in a 24-hour load curve are reordered greatest magnitude to least to fonn form a daily load duration curve. greatest

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commercial site with a 90 kW peak Figure 3.7 Annual load duration curve for a commercial 16. As shown here, in demand, from an example DG reliability study case in Chapter 16. that analysis the demand exceeds 40 kW, the capacity of the smaller of two DG units installed at the site, 2,800 hours a year. During those 2,800 hours, adequate service can be obtained obtained only if both units are operating.

often important aspect of siting for facilities, including DO DG (Willis, basis, an often 1996). Most often, load duration curves are produced reordering produced on an annual basis, reordering all 8,760 hourly demands (or all 35,040 quarter hour demands if using 15minute demand intervals) in the year from highest to lowest, to form a diagram

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Chapter 3

minimum) like that in Figure 3.7. The load shown was above 26 kW (demand minimum) 8,760 hours in the year, never above 92 kW, but above 40 kW for 2,800 hours. Spatial Patterns of Electric Demand

electric utility must not only produce or obtain the power An electric power required by its consumers, but also must deliver it to their locations. Electric consumers consumers are scattered scattered throughout the utility service territory, and thus the electric load can be spatial basis as depicted in Figure 3.9. Just as load thought of as distributed on a spatial curves show how electric load varies as a function of time, (and can help identify when certain amounts of power must be provided), so has Spatial Load Analysis been used since its development in the 1970s 1970s (Scott, 1972) to identify where load is located and how much capacity is needed in each locality. The electric demand in an electric utility service territory varies as a function of location depending on the number and types of consumers in each locality, as Load densities in the heart of a large city shown by the load map in Figure 3.9. Load can exceed 1 MW/acre, about 5 MW per square MW lacre, but usually average about square mile over the entire metropolitan area. In sparsely populated rural areas, farmsteads can be as far as 30 miles apart, and load density as low as 75 watts per square mile. Regardless of whether an area Regardless area is urban, suburban, or rural, electric load is a function of the types of consumers, their number, their uses for electricity, and the appliances they employ. Other aspects aspects of power system performance, performance, reliability, can also be analyzed on a locationlocationincluding capability, cost, and reliability, of siting for facilities, including including DG basis, an often important aspect of DO (Willis, 1996).

:: Lo-densRes. ;=;

Residential

111

Apartments



Retail



Offices



Hi-nse

» Lgt.lnd.

E

MKt. Ind.

Figure 3.8 (Left) Map showing types of consumer by location for a small city. (Right) of electric demand for this same city. map of

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Consumer Demand for Power and Reliability of Service

97

3.3 ELECTRIC ELECTRIC CONSUMER CONSUMER NEED FOR QUALITY OF POWER

As mentioned in this chapter's introduction, of introduction, a central issue in customer value of service analysis is matching availability availability and power quality against cost. T &D T&D systems with with near perfect availability and power quality can be built, but their high cost will mean electric prices the utility customers may not want to pay, of given the savings an even slightly less reliable system would bring. All types of utilities have an interest in achieving the correct correct balance of quality and price. The traditional, franchised monopoly monopoly utility, in its role as the "electric resource manager" for the customers it serves, has a responsibility to build a system whose quality and cost balances its customers' needs. A competitive retail distributor of power wants to find the best quality-price combination - only in that way will it gain a large market share. While it is possible to characterize various power quality problems in an engineering sense, characterizing them as interruptions, voltage sags, dips, surges, or harmonics the customer perspective is somewhat different. different. Customers are concerned with only two aspects of service quality: 1. They want power when they need it. 2. They want the power to do the job. If If power is not available, neither aspect is provided. However, if power is available, but quality is low, only the second is not provided.

Assessing Value of Quality by Studying the Cost of a Lack of It In general, customer value of reliability and service quality quality are studied by assessing the "cost" that something less than perfect reliability and service quality creates for customers. Electricity provides a value, and interruptions or poor power quality decrease that value. This value reduction - cost - occurs for a variety of reasons. Some costs are difficult, if not impossible to estimate: rescheduling of household activities or lack of desired entertainment when power fails;11 or flickering flickering lights that make reading more difficult. difficult. But often, very exact dollar figures figures can be put on interruptions and poor qUality. Food spoiled due to lack of refrigeration; wages and other power quality. operating costs at an industrial plant during time without power; damage to product caused by the sudden cessation of power; lost data and "boot up" time for computers; equipment destroyed by harmonics; and so forth. Figure 3.9 shows two examples of such cost data. 1

I

No doubt, doubt, the cost of an hour-long hour-long interruption interruption that that began began fifteen minutes minutes from the end of a crucial televised sporting event, or the end of a "cliffhanger" would be "cliffhanger" movie, movie, would claimed to be great.

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Chapter 3

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30

Distortion - % Total Harmonic Voltage Distortion·

Figure 3.9 Left, cost of a week-day week-day interruption of service to a pipe rolling plant in the southeastern United States, as a function of interruption duration. duration. An interruption of any length costs about $5,000 - lost wages and operating costs to unload material in process, bring machinery back to "starting" position and restart - and a nearly linear cost thereafter. At right. right, present worth of the loss of life caused by harmonics harmonics in a 500 horsepower three-phase industrial site. horsepower three-phase electric motor installed installed at that same industrial site, as a function function of harmonic voltage distortion.

Value-Based Planning customers To be of any real value in utility planning, information of the value customers put on quality must be usable in some analytical analytical method that can determine the best way to balance quality against cost. Value-based planning planning (VBP) is such a method: it combines customer-value data of the type shown in Figure 3.9 with &D system to various levels of reliability reliability and data on the cost to design the T T&D power quality, quality, in order to identify identify the optimum balance. Figure 3.10 illustrates the central tenet of value-based planning. planning. The cost incurred by the customer due quality, and the cost to build the system to to various levels of reliability or quality, various levels of reliability, reliability, are added to get the total cost of power delivered to the customer as a function of quality? quality.2 The minimum value is the optimum balance between customer desire for reliability and aversion to cost. This This approach can be applied for only reliability aspects, i.e., value-based reliability planning, or harmonics, or power quality overall. Generally, what makes sense 1

2

Figure 3.10 illustrates the concept of VBP. In practice, the supply-side reliability curves curves often often have discontinuities and significant non-linearities that make application difficult. difficult. These and other details will be discussed in Chapter 5.

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99

Consumer Demand for Power and Reliability of Service Customer Value of Quality

Utility Cost of Providing Quality

Sum of Costs

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Figure 3.10 Concept of value-based planning. planning. The customer's cost due to poorer varying levels levels of quality quality (left) and the cost of various power delivery designs with varying (center) are computed over a wide range. When added together (right) they form the total which identifies the minimum minimum cost reliability reliability level (point A). cost of quality curve, curve, which

is to apply it on the basis of whatever qualities (or lack of them) impact the customer - interruptions, interruptions, voltage surges, harmonics, etc., in which case it is quality of service planning. comprehensive value-based quality Cost of Interruptions

affects the most customers, and which receives the The power quality issue that affects most attention, attention, is cessation of service often often termed "service reliability." Over a utility will period of several years, almost all customers served by any utility experience at least one interruption of service. By contrast, a majority will never experience experience serious harmonics, voltage surge, or electrical electrical noise problems. Therefore, among all types of power quality issues, interruption of service receives the most attention from both the customers and the utility. utility. A great deal of more information is available about cost of interruptions than about cost of harmonics or voltage surges. Voltage Sags Cause Momentary Voltage Momentary Interruptions Interruptions

continuity of power flow does not have to be completely interrupted to The continuity disrupt service: If voltage drops below the minimum necessary for satisfactory operation of an appliance, power has effectively effectively been "interrupted" "interrupted" as illustrated in Figure 3.11. For this reason many customers regard voltage dips and sags as momentary interruptions interruptions - from their perspective these are interruptions interruptions of the end-use service they desire, if not of voltage. Much of the electronic equipment manufactured in the United States, as well as in many other countries, have been designed to meet or exceed exceed the CBEMA

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100

Chapter 3

O)

±3

A

i• v

v v

v

v V

A

A A

A

A

i / v v v v v v v

Figure 3.11 Output of a 5.2 volt DC power supply used in a desktop computer (top) and the incoming AC line voltage (nominal 113 volts). volts). A voltage sag to 66% of nominal causes power supply output to cease within three cycles. cycles.

200

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10' 105

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Time In in Cycles

Figure 3.12 3.12 CBEMA CBEMA curve of voltage deviation versus period period of of deviation, with the sag shown in Figure 3.11 plotted (black dot).

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Consumer Demand for Power and Reliability of Service

101

(Computer and Business Equipment Manufacturer's Association) recommended curves for power continuity, continuity, shown in Figure 3.12. If a disturbance's voltage deviation and duration characteristics are within the CBEMA envelope, then normal appliances should operate normally and satisfactorily. However, many appliances and devices in use will not meet this criterion at all. Others will fail to meet it under the prevailing ambient electrical conditions (i.e., line voltage, phase unbalance power factor and harmonics may be less than perfect). The manner of usage of of an appliance also affects affects its voltage sag sensitivity. The voltage sag illustrated in Figure 3.11 3.11 falls just within the CBEMA curve, as shown in Figure 3.12. The manufacturer probably intended for the power supply to be able to withstand nearly twice as long a drop to 66% of nominal voltage before ceasing output. output. However, the computer in question had been upgraded with three times the standard factory memory, a second and larger hard drive, and optional graphics and sound cards, doubling its power usage and the load on the power supply. supply. Such situations are common and means that power systems that deliver voltage control within recommended CBEMA standards may still provide the occasional occasional momentary interruption. For all these reasons, there are often often many more "momentary "momentary interruptions" interruptions" at a customer site than purely technical evaluation based on equipment Momentary specifications and T&D T &D engineering data would suggest. interruptions usually usually cause the majority of industrial and commercial interruption problems. In addition, they can lead to one of the most serious customer dissatisfaction issues. Often utility monitoring and disturbance recording equipment does not "see" "see" voltage disturbances unless they are complete cessation cessation of voltage, or close to it. Many events that lie well outside the CBEMA curves and definitely lead to unsatisfactory equipment operation are not recorded or acknowledged. As a result, a customer can complain that his power has been interrupted five or six times in the last month, and the utility will insist that its records show power flow was flawless. flawless. The utility's utility's refusal refusal to acknowledge acknowledge the problem irks some customers more than the power quality problem itself. itself. Frequency and Duration of Interruptions Both Impact Cost

Traditional Power System Reliability Analysis recognizes recognizes that service interruptions have both frequency and duration (See Chapter 4). Frequency is (usually a year) that power is the number of times during some period (usually interrupted. Duration is the amount of time power is out of service. Typical values for urban/suburban power system performance in North America are 2.2 interruptions per year with 100 minutes total duration. Both frequency and duration of interruption impact the value of electric

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102

Chapters

service to the customer and must be appraised in any worthwhile study of of customer value of service. A number of reliability studies and value-based customer planning methods have tried to combine frequency frequency and duration in one manner or another into "one "one dimension." A popular approach is to assume all interruptions are of some average length (e.g., 2.2 interruptions and 100 minutes is assumed to be 2.2 interruptions per year of 46 minutes each). Others have assumed a certain portion of interruptions interruptions are momentary and the rest of the duration is lumped into one "long" interruption (i.e., 1.4 interruptions of less than a minute, and one 99-minute interruption interruption per year). Many other approaches have been tried (see References and Bibliography). But all such methods are at because frequency and duration impact different best an approximation, because customers in different way. No single combination of the two aspects of aspects of reliability can fit the value structure of of all customers. customers. Figure 3.13 shows four examples of the author's preferred of preferred method of assessing interruption interruption cost, which is to view it as composed composed of two components, components, assessing fixed cost (Y intercept) caused when the interruption interruption occurred, and a variable variable a fixed cost that increases as the interruption interruption continues. As can be seen in Figure 3.13, 3.13, sensitivity to these two factors varies greatly. The four examples are: customer sensitivity 1.

A pipe-rolling factory (upper left). After an interruption of of any length, material in the process of manufacturing must be cleared from the welding and polishing machinery, machinery, all of which must be reset and the raw material feed set up to begin the process again. This 1/2 hour and sets a minimum cost for an interruption. takes about 112 Duration longer longer than that is simply a linear function of the plant operating time (wages and rent, etc., allocated to that time). Prior to changes made by a reliability reliability study, study, the "re-setting" "re-setting" of the machinery restored (i.e., time during the could not be done until power was restored re-start once it was interruption could not be put to use preparing to re-start The dotted line shows the new cost function after over). modifications to machinery and procedure were made so that preparations could begin during the interruption. interruption.

2.

An insurance claims office (upper right) suffers loss of data equivalent to roughly one hour's processing processing when power fails. According to the site supervisor, an unexpected power interruption causes loss of about one hour's work as well as another estimated estimated half hour lost due to the impact of any interruption on the staff. staff. Thus, the fixed cost of each interruption is equivalent to about ninety minutes of work. After one-half one-half hour of interruption, interruption, the supervisor's policy is to put the staff staff to work "on other stuff for a while," making cost impact lower (some productivity); productivity); thus, variable down. The dotted line shows the cost impact interruption cost goes down.

Copyright © 2001 by Taylor & Francis Group, LLC

Consumer Demand for Power and Reliability of Service

Pipe Roiling Rolling Plant

Insurance Claims Office

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Figure 3.13 The author's recommended recommended manner of assessing of 3.13 assessing cost of interruptions includes evaluation of service interruptions on an event basis. Each interruption has a fixed cost (Y-intercept) and a variable cost, which increases as the interruption continues. Examples given here show the wide range of customer cost characteristics that exist. The text gives details on the meaning of solid versus dotted lines and the reasons behind the curve shape for each customer.

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104

3.

4.

Chapters interruptions after installation installation of UPS on the computer system, which of interruptions permits permits orderly shutdown in the event of an interruption. An acetate manufacturing manufacturing and processing processing plant (lower left) has a very non-linear cost curve. Any interruption of service causes $38,000 in productivity and after-restoration set-up time. Cost Cost rises slowly lost productivity for about half an hour. At that point, molten feedstock and interim ingredients inside pipes and pumps begins to cool, requiring a dayprocess of cleaning sludge and hardened hardened stock out of the long process system. The dotted line shows the plant's interruption cost function after after installation of a diesel generator, started started whenever interruption time exceeds exceeds five minutes. interruption cost function (lower Residential interruption (lower right), estimated by the authors from a number of sources sources including a survey of customers made for a utility in the northeastern United States in 1992, shows except for roughly linear cost as a function of interruption duration, except two interesting features. features. The first is the fixed cost equal to about eight minutes of interruption at the initial variable cost slope which reflects "the "the cost to go around and re-set re-set our digital clocks," along with similar inconvenience costs. Secondly, a jump in cost between 45 and 60 minutes, which reflect reflect inconsistencies inconsistencies in human reaction reaction to outage, time on questionnaires. The dotted line shows the relation the authors' uses in their analysis, which makes adjustments adjustments thought reasonable to account for these inconsistencies. reasonable

This recommended recommended analytical approach, in which cost is represented represented as a function of duration on a per event basis, requires more information and more analytical effort effort than simpler "one-dimensional" "one-dimensional" methods, but the results are more credible. credible.

Lower if Prior Prior Notification is Given Given Interruption Cost is Lower most of tile the Given sufficient time to prepare for an interruption of service, most momentary interruption cost (fixed) and a great deal of the variable cost can be eliminated eliminated by many customers. Figure 3.14 shows the interruption cost figures from Figure 3.13 adjusted for "24 hour notification notification given." Customer Class Cost of Interruption Varies by Customer Cost of power Cost power interruption varies among all customers, but there are marked distinctions among classes, classes, even when cost is adjusted for "size" of load by computing functions on a per kW basis. Generally, the residential class computing all cost functions commercial the highest. Table Table 3.14 has the lowest interruption cost per kW and commercial

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105

Consumer Demand for Power and Reliability of Service Table 3.1 Typical Interruption Costs by Class for Three Table Three per kilowatt hour) Utilities - Daytime, Weekday Weekday (dollars per

1

2

3

3.80 3.80 4.50 4.50 27.20 27.20 34.00 7.50 7.50 16.60 16.60

4.30 4.30 5.30 5.30 32.90 27.40 1l.20 11.20 22.00

7.50 7.50 9.10 9.10 44.80 52.10 52.10 13.90 13.90 44.00

Class Agricultural Residential Retail Commercial Other Commercial Commercial Industrial Municipal

Pipe Roiling Rolling Plant

Insurance Claims Office Claims Office

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Figure 3.14 3.14 If an interruption of service is expected expected customers customers can take measures to reduce its impact and cost. Solid lines are the interruption costs (the solid lines from Figure 3.13). Dotted Dotted lines show how 24-hour notice reduces the cost impact in each case.

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Chapters

gives the cost/kW of a one-hour interruption of service by customer class, obtained using similar survey techniques techniques for three utilities utilities in the United States: 1. 2. 3.

A small municipal system in the central plains, an urban/suburban/rural urban/suburban/rural system on the Pacific Coast and, an urban system on the Atlantic Atlantic coast.

Cost Varies from One Region to Another Another

apparently similar customer classes can vary greatly Interruption costs for apparently depending on the particular region of the country or state in which they are differences. The substantial located. There are many reasons for such differences. difference difference (47%) between industrial costs in utilities I1 and 3 shown in Table Table 3.14 is due to differences in the type of industries that predominate in each region. The differences between residential costs of the regions shown reflect different varying degrees of economic health in their different demographics and varying respective regions. Customers within a Class Cost Varies among Customers The figures given for each customer class in Table 3.14 represent an average of of values within those classes as surveyed and studied in each utility service territory. Value of availability can vary a great deal among customers within within a utility service territory and even among neighboring any class, both within industrial class, where different different sites. Large variations are most common in the industrial interruption, as shown in Table needs can lead to wide variations in the cost of of interruption, 3.2. Although documentation is sketchy, indications indications are the major major differing differing factor is the cost of factor of a momentary momentary interruption interruption - some customers are very sensitive to any cessation of power flow, while others are impacted mainly by something longer than a few cycles or seconds. Cost of Interruption Varies as a Function of Time of Use

Cost of interruption will have a different different impact depending on the time of use, usually being much higher during times of peak usage, as shown in Figure 3.17. However, when adjusted to a per-kilowatt basis, the cost of interruption can sometimes sometimes be higher during off-peak than during peak demand periods, as shown. There are two reasons. First, the data may not reflect actual value. A survey of 300 residential customers for a utility in New England revealed that evening (Figure customers put the highest value on an interruption interruption during early evening 3.17). There could be inconsistencies in the values people put on interruptions (data plotted were obtained by survey).

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107

Consumer Demand for Power and Reliability of Service Table 3.2 Interruption Costs by Industrial Sub-Class for One hour, Daytime, Weekday (dollars per kilowatt)

$/kW $IkW

Class Bulk plastics refining Cyanide plant Weaving (robotic loom) Weaving (mechanical loom

38 87 72 17

Automobile recycling

3 44 12 8

Packaging Catalog distribution center Cement factory

However, there is a second, and valid, reason reason for the higher cost per kilowatt off-peak: only essential equipment, such as burglar off-peak:: burglar alarms, security lighting and refrigeration refrigeration is operating - end-uses that have a high cost of interruption. While it is generally safe to assume that the cost of interruption is highest during peak, the same cannot be assumed about the cost per kilowatt.

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Figure 4.1 4.1 Data from 67 disturbances which occurred over a two-year period at a clothing factory, plotted against the CBEMA curve (solid line) and the actual requirement requirement of a digitally-controlled envelope of digitally-controlled hosiery loom (dotted (dotted line). line). In many systems, about of the CBEMA 40% of of all voltage sags and 10% of of all voltage surges lie outside of envelope. Small circle refers to event mentioned in text text.

4.3 RELIABILITY RELIABILITY INDICES INDICES In order to deal meaningfully with reliability as a design criterion for distribution, it is necessary to be able to measure it and set goals. A bewildering range of of reliability indices is in use within the power industry. industry. Some measure only frequency of of interruption, others only duration. A few try combining both frequency and duration into a single value, which proves to be nearly an impossible task. Some measures are system-oriented, looking at reliability averaged over the entire customer base. Others are customer or equipmentoriented, meaning that they measure reliability reliability only with regard to specific sets of of customers or equipment. equipment. To complicate matters further, most utilities use more than one reliability index to evaluate their reliability. of reliability. The large number of indices in use is compelling evidence that no one index is really superior to any other. In fact, the authors are convinced that no one index alone is particularly useful. The basic problem in trying to measure reliability is how to relate the two quantities, frequency and duration. Are two one-hour interruptions equivalent to one two-hour interruption, interruption, or are two one-hour interruptions interruptions twice as bad as the one two-hour interruption? Most people conclude that the correct answer lies somewhere in between, but no two electric service planners, and no two electric

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Chapter 4

frequency and duration consumers for that matter will agree on exactly how frequency "add "add up" in importance. For one thing, the importance of frequency and duration vary tremendously from one electric consumer to another. There are some industries where a one-minute interruption of of power will cause over ninety minutes of of lost productivity. Computer and robotic systems must be reset and restarted, or a long production process must be cleared and bulk material reloaded, before the plant can restart at the beginning of of a production cycle. For these types of consumers, five one-minute outages are much more serious than a single outage, even if if it is five hours duration. But there are other customers for whom short outages cause no significant problems, but who experience inconvenience during a sustained outage. This category includes factories or processes processes such as pulp paper mills, where production is only damaged if equipment has time to "cool down." Interruption of power to a heater or tank pressurized of power pressurized for a minute or two is not serious serious (although it might be inconvenient), but sustained interruption allows a cooldown or pressure drop that results in lost production. Over the last two decades of of the 20th century, frequency of of interruption became increasingly important to a larger portion of the electric power market. Before the widespread use of of digital clocks and computerized equipment, few residential or commercial customers cared if power was interrupted briefly (for a few minutes at most) in the early morning (e.g., 3:00 AM) while the electric utility performed switching operations. It was common practice for utilities utilities to perform minor maintenance and switching operations during that period to minimize any inconvenience to their customers. Today, this practice leads to homeowners who wake up to a house full of of blinking digital displays, and wake homeowners up later than they expected, because their alarm clocks did not operate. The amount of of power interrupted is also an important factor. factor. Some reliability calculations and indices are weighted proportionally to customer load at the time of of interruption, or to the estimated energy (kWh) not delivered during the interruption. However, the four most popular indices used in reliability analysis make no distinction of of demand size. They treat all customers in a utility system alike regardless regardless of of peak demand, energy energy sales, or class. These measure only frequency, and SAlOl indices are SAIFI and CAIFI, which measure SAIDI and CTAIDI, which measure only duration. duration. Usually these four are used in conjunction - four numbers that give a rough idea of what is is really happening to system-wide. reliability system-wide. These four indices, and most others, are based on analysis of customer interruptions during some reporting interruptions reporting period, usually the previous month or year. All count a customer customer interruption as the interruption of service to a single customer. If If the same customer is interrupted three times in a year, that constitutes three customer interruptions. If one equipment outage caused of service of of three customers, that too is three simultaneous interruption of

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Power System Reliability and Reliability of Service

127

customer interruptions.

System Average Interruption Frequency Index (SAIFI) (SAIFI) is the average number of of interruptions per utility customer during the period of of analysis. SAIFI == number of customer interruptions total customers in system

(4.1)

Customer Average Interruption Frequency Index (CAIFI) (CAIFI) is the average number of of interruptions experienced by customers who had at least one interruption during the period. CAlF! CAIFI ==

number of customer interruptions number of of customers who had at least one interruption

(4.2)

The "S" in SATF! SAIFI means it averages the interruption statistic over the entire customer base (the ~stem), system), the "C" in CAIFI means it refers to only £ustomers customers customer experienced interruptions. Customers who had uninterrupted service who experienced during the period are precluded from from CAlF!. CAIFI. System Average Interruption Duration Index (SAIDI) (SAIDI) is the average duration of of all interruptions, obtained by averaging over all the utility customers - those all of the who had outages and those who did not. SAIDI == sum of of the durations of of all customer interruptions total customers in system

(4.3)

Customer Total Average Interruption Duration Index (CTAIDI) (CTAIDI) is the average total duration of of all interruptions, but averaged only over the number of of utility customers who had at least one outage. CTAIDI ==

sum of of the durations of (4.4) of all customer interruptions number of of customers who had at least one interruption

Momentary Momentary Interruption Index

Momentary Average Interruption Frequency Index (MAIFI) Momentary (MAIFI) is the average number of of momentary (and sometimes instantaneous) interruptions per utility customer during the period of of analysis,

MAIFI == number of of customer momentary interruptions total customers in system

(4.5)

Often, momentary interruptions are not included in the SAIFI value reported by an electric utility. In such cases, total interruptions interruptions (from the consumer SAIFI + MAIFI. standpoint) are best estimated by the sum: SATFI MATFI.

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128

Chapter 4

Load Curtailment Indices

In addition, addition, a number of of indices try to relate reliability to the size of of customer interruption of loads, in order to weight the interruption of a large load more than a small load, A unserved Customer load curtailment = duration of of outage x kY kVA

(4.6)

Customer Average Load Load Curtailment Index Index (CALCI) (CALCl) is the average average kYA kVA x duration interrupted per affected affected customer, per year CALCI= sum of CALCI — of all customer load curtailments curtailments number of of customers who had at least one interruption

((4.7) 4.7)

Normal Normal usage usage is often often sloppy and and informal informal Even though the "s" "S" in the terms SAlOl SAID1 and SAIFI means, "averaged over over the entire system," internally report "SAlOl" system," some utilities internally "SAIDI" and "SAlFI" "SAIFI" values by feeder. While While strictly strictly speaking, SAlOl SAIDI and SAIFI are the same for all feeders (they (they are computed computed by being averaged averaged over the entire system), it is understood that what they mean is the average average annual annual duration and frequency for customers customers on that feeder. feeder. Similarly, Similarly, engineers at these and other utilities often use the two terms when they mean "duration" "duration" and "frequency" "frequency" of of interruptions interruptions for an area area of of of customers. the system or a small small group of

Analysis Using Reliability Analysis Reliability Indices Reliability indices are used to evaluate historical historical and recent data to reveal trends trends and patterns, expose problems, and reveal how and where reliability reliability can be improved. Any of of the reliability indices indices discussed above can be tracked over time to identify identify trends that indicate developing problems. Figure 4.5 shows frequency of customer interruption (SAIFI) of customer (SAIFI) for one suburban operating district of metropolitan utility on an annual of a metropolitan annual basis over a 35-year period. The operating district was open farn1land farmland (no tree-caused trouble) trouble) up to 1962. At that time suburban growth of of a nearby metropolitan region first spilled into the area, with construction and with it the typically high interruption interruption rates characteristic much construction characteristic of of construction areas (trenchers digging into underground lines, early equipment of new distribution facilities, etc.). failures of Over the following ten years, as the area plotted in Figure 4.5 gradually filled Over following (en in with housing and shopping centers and construction and system additions stabilized, frequency frequency of of interruption dropped. Twenty Twenty years after after the area first began because of began developing; developing; interruption rate again began to rise because of two factors: I. Gradually 1. Gradually increasing cable failure rates due to age. 2. The effects of of trees, planted when the area first developed, reaching reaching a

height, where they brushed against bare conductors on overhead lines.

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129

Power System Reliability and Reliability of Service

..

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Figure 4.2 Three-year Three-year moving average of of the annual number of of interruptions for a region of of a utility utility in the central United States. This area grew from open farmland into a developed metropolitan suburb in the period from 1962 to 1970, during which time interruption rate rose due to the problems common to areas where new construction is present (digging into lines, initial above-average above-average failure rates for newly installed present of equipment). Twenty years later, interruption rate began to rise again, a combination of the effects of of aging cable (direct buried laterals in some residential areas) and trees, planted when the area was new, finally reaching a height where they brushed against overhead conductor. The anomaly centered on 1982 was due to a single, bad storm.

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Feeder System Strength (Percent of Substation Load Transferable to Neighboring Substations)

Figure 8.9 Feeder system strength of Figure strength (inter-substation (inter-substation tie capacity) capacity) vs. utilization ratio of transformers under normal conditions transformers conditions that can be tolerated tolerated while still preserving preserving transformer at a two-transformer two-transformer substation. contingency capability for the outage of contingency of a transformer For example, the graph indicates that if a contingency contingency loading loading of of 166% 166% is allowed by standards, then normal target loading must be limited to 83% if the feeder strength is zero, but can go to 100% if feeder strength strength is 17%.

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utilization ratio and feeder system strengths needed to assure full contingency contingency V-intercept values capability when contingency loading is limited to 133%. The Y-intercept represent the maximum utilization ratio that a utility can use for each of of the lines represent at a two-transformer substation given that no load will be transferred to neighboring substations in the event of of a transformer outage. As can be seen, greater utilization greater transfer capability through the feeder system means greater utilization ratios can be applied in the normal operation of of the system. Loss of Contingency Reach Due to Obsolete System Layout

"Reach" is the distance that a feeder system can move power while staying with the voltage standards applicable for its operating conditions. For example, a 12.47 kV, three-phase, overhead overhead feeder of of typical industry design, using 4/0 ACSR conductor, can move power corresponding to its thermal limit (the maximum amount of of power possible within its current rating, 340 amps/phase, corresponding to 7.3 MVA) a distance of of I. 1. 8 miles before voltage drop on the line reaches 7.5% - the maximum permitted permitted on the feeder system according according to many electric utility voltage standards. This distance is 4/0's 4/0's thermal reach. reach. Substitution of of another conductor will not materially materially change this distance: 336 conductor will move its thermal limit (530 amps corresponding to 11.5 MV A) 1.8 A) will move its thermal limit MVA) 1.8 miles; 636 AA (770 amps, 16.6 MV MVA) 1.7 miles; miles; #2 ACSR (130 amps, 2.8 MVA), 1.8 1.8 miles. The larger conductor has lower impedance (less voltage drop per ampere) but a higher thermal limit. The two factors compensate for one another. Thus, the thermal reach of a 12.47 kV feeder system system and the distance it can move power if if operating at its thermal limits is 1.8 1.8 miles, regardless of of conductor size. Economic reach refers to the distance that power will travel on feeder Economic segments before encountering encountering the maximum allowed voltage drop, in situations conductor size and loading have been selected so that all conductor operates at or near its most economical economical loading level over the course of of a year.8 year. The economic factors, factors, load characteristics, and design standards that affect affect utility. But again, the determination determination of of economic economic loading vary from utility to utility. economic reach of of each type of of conductor turns out to be about the same. Under typical conditions economic reach works out out to to about 3.6 3.6 miles - about twice thermal reach (economical loads are usually about Y, !/2 the thermal limit). Contingency power can be moved on the Contingency reach refers to the distance that power feeder system under contingency conditions, when higher loading levels and more liberal voltage drop limits that are permitted. Again, standards vary from

8 8

See the Power Distribution Distribution Planning Reference Reference Book, Book, Chapter 7, 7, Section 8.3 8.3 for a loading is determined conductors. detailed explanation explanation of of how economic loading determined for conductors.

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one utility to another. But as an example the ANSI C84.1-1989 standard specifies range A voltages as design criteria for normal conditions on the system, with a 7.5% maximum voltage drop on the primary feeder system permitted (9 volts on a 120 120 volt scale). It states that Range B voltage ranges apply in emergency emergency situations, permitting up to 13 13 volts on a 120 volt scale (10.8% voltage drop).9 drop).9 Thus, according to this standard, during a contingency a distribution utility is affected area with up to 10.8/7.5 equals 144% permitted to operate feeders in the affected more voltage drop than under normal conditions. This 44% additional voltage drop can be "spent" by either moving more power (more current equals more voltage drop) or by moving power over a longer distance (longer distance equals more voltage drop), or in some combination of of more power moved a greater distance which is the normal case. Generally, due to a bit of of of margin built into a feeder system for a variety of secondary and tertiary reasons, there will be a bit more voltage drop margin than minimum.1O minimum.10 Thus, under most circumstances circumstances it would be reasonable to expect about 50% 60% to be the the permissible additional margin, over and and above 50% - 60% normal peak load conditions, rather than just the 44%. Consider again Figure 8.8 and its example of of transfers to other substations. Note that 22.5% of of each feeder's load is transferred to neighboring feeders. Roughly speaking, the additional distance for power flow is about 20% farther (assume for the moment that the other substation areas/feeder areas are the same size and shape as those in the drawing). Thus, additional loading times additional distance (122.5% x 120%) is very close to the 144% limit. If If this feeder system is well designed and operated such that normal loadings are kept in the most economical range for all conductors (as it ideally would be) then no substantial reinforcement of of its elements should be required to provide the required level of contingency support. Little if if any additional capacity needs to be installed to provide this contingency support. A well-designed feeder system with all conductors conductors sized to be most economical, and with switching designed for inter-substation inter-substation support, can be built at very little if any additional cost (beyond the extra planning and engineering work required) over a system that docs does not have these capabilities. capabilities.

9

— Recommended Recommended Practice Practice for Electric Power Distribution Distribution for for See the IEEE Red Book -for Electric Industrial Plants. Industrial Plants. 10 10 There are only a limited number of of different different conductors available. Often in "optimally "optimally si/ing" a particular segment segment engineers determine that one size is a bit too small, the next sizing" size a bit too large, to be exactly optimal. Necessity Necessity dictates dictates they pick the larger size, necessary - additional margin which provides a bit lower voltage, drop than technically necessary for contingencies, among other things. In typical systems this adds about 10% to the available voltage drop margin. 9

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consider what happens when the loading on the feeder system is However, consider occurred to Metropolitan Power Power and Light permitted to creep upwards, as occurred of three and one half half decades decades an example case in Section 8.2. Over the course of of increased loading on the feeder system was accepted as an inevitable result of changes the utility could not stop. Although reinforcement reinforcement of of the feeder system changes time, substituting larger conductor where necessary, necessary, was done from time to time, of the feeder system ended up running at above their most many portions of economical loading ranges. As a result, they lose reach. The net result is that a situation situation like that depicted depicted in Figure 8.10 can occur during a contingency. There, two feeders for neighboring substations are shown (each a triangular area corresponding to the triangular feeder areas in Figure 8.8). The rightmost feeder's substation transformer has failed. Its outer 22.5% load has been un-switched from the substation (opening switch B), and the feeder tie switch at point A closed, so that the feeder at the left can pick up the outer most load from feeder B. Due to higher feeder loadings, the feeder system capability. The dotted line does not have the contingency reach to provide this capability. Figure 8.10 shows where voltage drops below unacceptable levels. in Figure The outdated system structure structure issues discussed in Section 8.2 created two effects situation: effects that led to this situation: 1. I.

Loss of of contingency capability. capability. A combination combination of of higher substation substation utilization ratios and higher loadings on the feeder system lead to a of capability available/capability available/capability needed. large shift in the ratio of Higher substation ratios raise the amount of of load that needs to be transferred transferred over the feeder system during contingencies. Also, higher loadings on the feeder system reduce the voltage drop margin available for contingency reach. As a result, the number of of situations and hours per year (near peak) when contingencies cannot be supported increases. Reliability of service service suffers. suffers. supported Reliability of

2.

Contingency preempted by planning. In many systems, Contingency capability capability preempted systems, pockets of of load growth growth are accommodated accommodated without local pockets of the feeder system in the area, via load transfers. For reinforcement of example, suppose that in Figure 8.9, the "contingency" that occurred was a planning contingency: the load in the feeder area on the right grew to be 10% more than that feeder could handle while staying within standards, but the feeder on the left had 10% margin. Utility planners can avoid any reinforcement cost by performing the switching operation shown, as a permanent solution to the "fixes" the normal operating problem "overloading" problem. This "fixes" at no cost, but leaves insufficient insufficient contingency capability in the system. This "solution" to local spot growth growth problems was common among among

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Obsolete System Structures

Range B limit

A

B

,,)/

," T

\ \

~

"

~

'"

r

l l

V

" , .... ,

~

" ,

0

V

TT l l "

,~

~

/

I

I

One Mile

I

Figure 8.10 Here, the feeder on the right has experienced substation experienced a failure at the substation opened, switch A has been closed, so the feeder on (shown by an X). Switch B has been opened, the left can support both all of of its load and the outlying 22.5% of of the other feeder's load (the rest is supported by switching switching the outaged feeder truck to another feeder near the serving 122.5 percent of of its normal load, over a substation). The feeder on the left is now serving distance of much as 15% more. Dotted lines show the points of transmission transmission that is as much where voltage drop reaches range B limit.

utilities throughout the 1990s. Since few used reliability-based, feeder of these system evaluation tools in such planning, the full impact of decisions on system reliability reliability was not fully recognized. recognized. Feeder Problems Often Don't Get the "Respect" They Are Due

critical to any utility's establishing a good record of of While the feeder system is critical reliability, failures there never cause the widespread, "headline grabbing" problems that failures failures at the substation and sub-transmission level can cause. of an entire feeder might drop service to between 500 and 1,500 The failure of customers. By contrast a bad problem at a substation can drop twenty feeders at once, causing a widespread outage that garners serious attention from newspapers and community leaders. efforts to fix aging infrastructure problems often focus on For this reason, efforts Still, the feeder system is an levels of the system other than the feeder system. Still, of the system, and as shown can be an important resource in important part of

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Chapter 8

limiting the the impact of substation - sub-transmission outages. Therefore, attention given to it is more important in the overall reliability equation than is often realized.

Outdated Structure Impact on the Feeder Feeder System: System: A Major Major Degradation in in System Reliability Reliability Regardless of of whether one or both of of the situations situations discussed above develop the Regardless effect effect on reliability is the same. A growing portion of of the equipment outages, could potentially of potentially lead to widespread, lengthy interruptions (i.e. outages of which could major equipment at the substations) now have no viable contingency support. In several large metropolitan systems outdated system structure issues (section 8.2) eroded feeder contingency support strength due to these two reasons, of what was required to meet system needs, a loss of of reasons, to less than 40% of 60%. Figure 8.5 8.5 showed that substation - sub-transmission sub-transmission related problems cause about 25% of of system SAIDI. Assuming again that Figure 8.5 is reasonably of frequency-of-outage causes in the system reasonably close to the distribution of degradation of of (see Footnote 6) and that degradation in results is proportional to degradation capability (it is actually worse), this 60% reduction in capability to support of a 15% substation-level problems would lead to something along the lines of increase (60% x 25). This impact on reliability is roughly three times the impact on system reliability that issues related to feeder system reliability cause (that came to 5%). Overall then, outdated system layout problems (section 8.2) lead to a 20% net increase in reliability problems, just due to their impacts on the feeder system alone. 8.6 "FIXES" "FIXES" FOR OUTDATED SYSTEM SYSTEM STRUCTURES STRUCTURES

There are no simple, inexpensive solutions to problems of of the magnitude discussed in this chapter. However, there are solutions, which are more discussed effective and less expensive than trying to reverse the various impacts of of aging effective infrastructure by adding more sites, more facilities, and reducing utilization ratios to traditional levels and practices. These require innovative approaches approaches that often break with traditional concepts and practices. Improved Communication with Community Community and Regulators Regulators Improved Communication Electric utilities have to do a better job of of identifYing identifying to those who approve their plans that new facilities and sites are needed if long-term reliability and service service quality is to be kept at high levels. The quality of of results that utilities obtain from their communication with regulators and community varies greatly. All utilities would be wise to emulate the methods employed by utilities that are

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269

particularly effective effective in this manner, such as PSE&G. Compact Compact Substation Substation Designs

The comprises of of capacity over configuration as illustrated by Figure 8.4 are simply unacceptable in a system where utilization rate is kept high and reliability is a priority. A better solution is to find a way to "cram" more capacity into existing sites. This can be done to two levels of of improvement:

1.

Compact designs. designs. Various means exist to reduce the space required for air-insulated substation equipment. Usually this entails rebuilding the substation upward rather than outward. Among the items used are "low footprint" transformers, and high rise buswork designed to use little horizontal real estate (which as a consequence has a much higher profile). Compact designs can typically increase the capability of a substation (as measured by additional capacity added without any up to 25 any sacrifice in configuration) by up 25 - 30%. Often this is not enough to provide all the improvement needed.

2.

Gas-insulated switchgear. The solution of of favor for crowded conditions in urban areas throughout Europe is the gas-insulated gas-insulated switchgear switchgear (GIS) substation, the so-called substation in a bottle. Slightly more than half half the metropolitan substations throughout Western Europe utilize GIS technology. GIS substations substations have all of of their busywork and breakers contained inside a set of of linked insulating capability. Voltage clearances between equipment can be much tighter than with air-insulated equipment, and the weatherprotection rendered by the enclosures enclosures and gas means that much more compact designs can be used for all equipment. As a result GIS equipment requires far less space than its air-insulated equivalents. GIS substations can increase the capability of of a substation site over that obtainable from the tightest possible use of of traditional airinsulated equipment, equipment, by a factor of of at least three. If If need be, an old 160 MVA site could be rebuilt with close to 500 MVA of capacity. Very often often full use of of this capability is not needed, but usually a doubling of of capability, or potential for eventual growth, is implemented when GIS is retrofitted to a site. GIS also makes sense as the construction standard for new substations in aging infrastructure areas, because it enables the utility to have a much wider choice of of available sites. Its compact nature and the fact that medium-sized buildings, means it will fit in it can be put inside medium-sized many places that previously had to be rejected. GIS substation equipment costs about 15% - 30% 30% more than

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Chapter 8 However it is slightly more reliable than, air-insulated alternatives. However and requires much less maintenance cost than, air insulated designs of equivalent capability, basically more than canceling out this high of of operation. In initial cost if evaluated over ten or more years of addition, its minimization minimization of of real estate needs also contributes to lower cost for land, a major consideration and often more than enough to offset offset the higher initial equipment cost.

Reinforcement of Feeder Trunks and Switching

of outdated system structures on the feeder system, Given the typical effects of providing the capability required of substation-level required for support of contingencies, will mean reinforcing feeder trunks with larger conductors, conductors, and installing additional additional switches for improved flexibility of of operation. This coordinated with is usually money well spent, and if planned well and coordinated contingency operation planning, feeder reinforcement for improved contingency among the most effective ways to spend limited funds to obtain obtain capability is among of service. improved reliability of Improved Planning Improved Improved planning can contribute significantly to a utility's both avoiding the situation depicted in this chapter, and mitigating its effects effects if it is already in such a situation. Good planning provides foresight, foresight, rational consideration consideration of of options, and under the right conditions, innovation. The following of recommendations should be taken as a whole: they provide the proper type of planning for aging infrastructure areas as well as for utilities who need to maximize both customer service and stockholder (financial) performance. 13 will discuss this in more detail. Chapters 12 and 13 Improved Improved long-range long-range planning planning

Section 8.2 cited ineffective ineffective long-range planning as a contributing cause to of the causes that ultimately lead to outdated structure and poor reliability. many of These problems have to be fixed before lasting solutions can be put in place. of several problems with traditional planning tools. Chapter 8 covers the nature of 12 discuss how improved planning methods and tools Chapters 11 and 12 appropriate for modem modern high utilization-ration systems can be effectively used. But more is needed. Section 8.2 showed that a large measure of of the problems utilities created created for themselves were due to simply not looking far enough ahead or not using long-range planning capability that was there. Thus, in addition to simply pay attention to and use method and technique, utilities must simply changes in method of long-term consequences consequences that flow the longer-tern perspective and evaluation of of long-range analysis of of the consequences consequences of out oflong-range of growth and aging.

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Two-Q approach

Part of of the failings outlined in Section 8.2 stem from an inability of of utilities to obtain sites, facilities, and equipment needed for purposes of of reliability. Part of of this stemmed from a flaw in the traditional utility-regulatory paradigm: planning, prioritization, and approval where based on capacity needs, not reliability needs. Chapter 4 introduced the concept of of Two-Q planning, in which both quantity and quality of of demand are viewed as burdens that set requirements for the system capability, and through which capability for both quality and quantity is arranged in an optimized fashion. Two-Q planning explicitly identifies situations where new sites and new equipment are needed not for capacity (kV (kVA) A) reasons alone, but for reliability reasons, and shows how much and why these needs arise. It makes such reliability-related requirements very clear and puts them in a context that is both communicate-able, where their justification is easier to make to executives and regulators alike. Two-Q is recommended both because it leads to a better understanding of reliability-related needs and the role elements of of a long-range plan may have with regard to reliability, and because it provides a much better format and more documentation of of need for their justification. Reliability-based feeder feeder system planning Reliability-based The feeder system can be designed in a reliability-based manner to provide both better reliability itself, and more contingency support for substations, using methods discussed in Chapters 11 and 12.

SUMMARY OF KEY POINTS POINTS 8.7 SUMMARY of problems created for a utility "Outdated system structure" refers to a host of when it cannot, or will not, expand its system's layout and number of sites in of power. Key company with the increasing demand for quantity and quality of of this impact are: aspects of 1.

of the system from fewer than an ideal number of of Operation of substation feed points

2.

Compromises in design that sacrifice configuration for capacity

3.

Acceptance of very high utilization rates, even if not the utility's economic standard, just because because there is no room for other options

4.

Degradation of of feeder system reliability and its ability to provide Degradation sub-transmission level outages. support during substation and sub-transmission

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Table 8.3 Overall Impact of of Outdated System Structure Issues on System Reliability Level Of Of System

Typical Amount of of Degradation

Substation/sub-transmission Feeder system reliability reliability Feeder system contingency support Total

15% - 20% 5% -15% - 15% 15% - 20% 35% - 45%

The net effect effect of of outdated outdated system structure issues, above and beyond the reliability indices (SAIDI impacts of of aging equipment itself, is an increase in reliability and SAIFI) due the substation - sub-transmission and feeder due to impacts on the sub-transmission and levels of of the system. Table 8.3 lists typical levels of of impact.

REFERENCES J. J. J. Burke, Power Power Distribution Distribution Engineering Engineering - Fundamentals Fundamentals and Applications, Applications. Marcel Dekker, New York, 1994 R. E. Brown, S. S. Venkata, and R. D. Christie, "Hybrid "Hybrid Reliability Optimization Methods for Electric Power Distribution Distribution Systems," Systems," International Conference on International Conference Intelligent Systems Applications to Power Power Systems, Intelligent Systems Applications Systems, Seoul, Korea, IEEE, July 1997.

S. S. Venkata, R.D. R.D. Christie, and R. Fletcher, 'Automated R. E. Brown, S. Gupta, S. Distribution System Design: Reliability Primary Distribution Reliability and Cost Optimization,' IEEE IEEE Transactions on Power Power Delivery, Delivery, Vol. Vol. 12, No.2, Transactions 12, No. 2, April 1997, 1997, pp. 1017-1022. 1017-1022. R.D. Christie, and R. Fletcher, 'Distribution R. E. Brown, S. Gupta, S. S. Venkata, R.D. System Reliability Assessment: Assessment: Momentary Interruptions and Storms,' IEEE System Reliability IEEE Transactions Power Delivery, Delivery. Vol. No.4, Transactions on Power Vol. 12, No. 4, Oct 1997, 1997, pp. 1569-1575. Recommended Practice Practice for for Design Design of Institute of of Electrical and Electronics Engineers, Recommended of Reliable Industrial Industrial and and Commercial Power Systems, Systems. The Institute of Reliable Commercial Power of Electrical and Electronics Engineers, Inc., Inc.,New NewYork, York, 1990. 1990.

H. L. Willis, Power Power Distribution Distribution Planning Planning Reference Reference Book, Book. Marcel Dekker, New York, 1997.

H. L. Willis and R. W. Powell, "Load "Load Forecasting for Transmission Planning," IEEE IEEE Transactions Power Apparatus Apparatus and Systems, Systems. August 1985, Transactions on Power 1985,p.p.2550. 2550.

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9 Traditional Reliability Reliability Engineering Engineering Tools and Their Limitations 9.1 INTRODUCTION INTRODUCTION 9.1 of aging T T&D The third of the five aspects of &D infrastructure discussed in Chapter 1I is Engineering Paradigms and Approaches. Traditional power system engineering methods, and the paradigms built around them, are as much a part of of existing power systems and their strengths and weaknesses, as old equipment and obsolete system layouts. Many of of the key concepts and engineerin~ engineering approaches used in "modem" "modern" power systems were created in the mid-20t mid-20 century, at a time when electric consumer demands, societal expectations, and engineering criteria were far different different from today's. Like all engineering methods, the mid-twentieth century's had their limitations and advantages. Those limitations were for the most part well understood by their developers, but were far outweighed by their advantages, among the most important being that the methods could be implemented with the very limited computing resources available at the time. The power industry has carried many of these engineering methods and the concepts built around them through several generations of power system engineers. Not only are these methods in widespread use, but several of of these paradigms have become dogma. This chapter will begin by examining the traditional power system reliability reliability engineering tool: the N-l criterion and the contingency-based contingency-based planning approach. This method was first used in the mid-20th century and had been 273 Copyright © 2001 by Taylor & Francis Group, LLC

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Chapter 9

developed into efficient efficient computerized form by the late 1960s. It, and the conceptual approach to power system planning that goes along with it, are at the core of reliability of nearly every utility's overall power delivery planning and reliability of the core concepts and criteria engineering procedures. Similarly, Similarly, many of distribution feeder systems were developed in the concerning the layout of of distribution 1930s through the 1960s, and are largely unchanged in their application application as the 21 stst century. These will be covered in Chapter electric utility industry enters the 21 10. These traditional power system-planning methods proved more than industry's needs through the 1950s to early 1990s. adequate to meet the industry's However, as experience has shown, and this chapter will explain, they are less than completely adequate for application to aging infrastructure areas in some of of today's high-stress utility systems. This is due to an incompatibility between these traditional planning methods and the way that modern modem utilities need to plan, design, and operate their systems. As a result, systems planned and designed along proven but traditional traditional lines, using tools that engineers engineers could once confidently use, often provide poor customer service reliability and experience severe operating problems. This chapter begins in section 9.2 with an examination of of the basic N-l N-I contingency-based of its contingency-based reliability reliability design criterion and the typical methods of application. Section 9.3 then explores this methodology's methodology's limitations with respect to modem modern needs, and discusses how they interact with the characteristics of of modem modern utility systems, and discusses how that often results in system that of reliability. reliability. Section 9.4 looks at some does not provide the expected level of other planning-related issues that have created real challenges for aging infrastructure utilities, most notably load forecasting errors and the way they interact with system reliability. reliability. Section 9.5 provides a reminder that high utilization rates and cost-reductions, per se, are not the reason that modem modern power systems and and particularly aging systems, tend to give poor results - rather reliability it is the inability of of traditional traditional planning tools to fully analyze the reliability implications of of design in those areas. Section 9.6 rounds out the chapter by effective planning summarizing summarizing keys points and gives five recommendations for effective procedures to be applied to aging infrastructure areas. 9.2 CONTINGENCY-BASED PLANNING METHODS

N-1 Criterion The N-1 The traditional power of power system planning method used to assure reliability of design at the its the sub-transmission - substation level is the N-l criterion. In its purest form, it states that a power system must be able to operate and fully meet of power (voltage, power factor, etc.) expectations for amount (kW) and quality of even if anyone any one of of its major components is out of of service (a single contingency).

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The system has N components, hence the name N-I. N-l. of sense. Unexpected equipment failures failures happen. This criterion makes a lot of Expected equipment outages (maintenance) are a fact of of life. A prudent approach to design reliability reliability should include making certain that the system can perform to its most stressful stressful required level (i.e., serve the maximum demand, the if a failure or maintenance outage has occurred. Just how much peak load) even if reliability this assures depends on a number of of factors that will be addressed later in this section and the fact that it does not always assure reliability reliability is the major topic of of this chapter. However, from the outset it seems clear that this criterion sets a necessary requirement for any power system this is expected to provide reliable reliable power supply. Extension of of the concept to multiple failures

The criterion can also be applied as an "N-2" criterion or "N-3' "N-3", criterion in which case the system must be able to perform to peak requirements even if any two or three units of of equipment are out of service, rather than one. Generalized, this becomes the N-X N-X criterion, criterion, the power system will satisfy satisfy expectations even if any set of of X and its components are out of of service. Regardless, the method is if generally referred to, and will be referred to here, as "the N-I" N-l" concept and criterion, even if X is greater than one.

Contingency Planning Concept Application of the Basic Contingency Typically, this concept is applied as a criterion in the planning and engineering of the transmission/sub-transmission/substation of an electric of transmissionlsub-transmissionlsubstation portion of distribution (T &D) system - the portion from 230 (T&D) 230 kV down to 69 69 or possibly 34.5 kV. At most electric distribution utilities, utilities, it is not applied to the distribution feeder system. Instead, techniques and analytical planning methods devised for application to radial power flow systems are used (see Section 9.3). The base case

Application of the N-I N-l criterion begins with a base case, a model of the power system as designed or planned, with all equipment in place and operating as intended. An appropriate engineering description of all this equipment along with a set of of expected peak loads that it will serve, forms the complete base case. In all modem procedures, this base case is a data set modern utility planning procedures, representing the system, to be used in a load-flow. A digital computer analysis will determine for the system represented by that data set, the power flows, voltages, power factors and equipment loadings that will result when that equipment set us asked to serve that demand. Various "minus one" or "contingency" cases are then done using this model as the base, literally literally deleting one element of of the data set at a time and "resolving" the model to see what

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effect effect that lose had on voltages, currents, etc. At the time the N-I N—1 method was first developed, (which was prior to the availability of of digital computers), the base case was an analog computer model built using patch-cord connections and numerical settings of of rheostats and switches on a network analyzer. Essentially, an analog computer computer built for simulation of of power system behavior. Since the mid-1960s, digital computer of simultaneous programs that solve the load flow computation using a set of equations have been used. By the end of of the 20th century, these programs programs had employed to make become very specialized, with features and analytical analytical tricks employed them fast, robust, and dependable when applied to contingency analysis. But regardless of the type of of engineering computer being used, studies that build upon, or more properly "delete upon" a base case are the foundation of of the contingency-analysis method. As a first step, a base case representing the system in "normal" form, i.e., with all equipment in operation and fully functional, is set up and solved, making sure that it (a system with all equipment operating) fully satisfies all loading, power quality, quality, and operating criteria. Contingency Contingency cases

"contingency Variations from this base case are then conducted as a series of of "contingency In each contingency study, one one particular unit of equipment - a key studies." In key transformer or line or bus, etc. is removed from the system database and the remaining system's performance studied using the engineering analysis model (load flow) applied to this "contingency "contingency case model." The analysis determines if the system can still serve all the demand, while remaining within specified operational operational criteria (see Table 9.1), with this one unit out of of service, or "outaged." If not, additions or upgrades are made to the system model until the case does meet the criteria. criteria. Once the first contingency case is completed (the study for the first component in the system), the method proceeds to study the outage of of the base case and of the second. It begins with a "fresh copy" of removes the second unit in the equipment list, again performing its analysis. In this way, it proceeds through all N components, outaging each one and identifying whether performance in that situation is sub-standard, thus giving planners an indication of of where problems in the system lie, and what the problems are. Relaxation of of design standards contingencies Relaxation standards for contingencies In most cases, electric distribution utility planners allow the contingency cases to meet less stringent requirements for loading, voltage, or other design goals, than for the "base" (no contingencies) case. For example, loading criteria may 100% of state that in the base case, no component can be loaded to beyond 100% of its normal rating. However, during any single contingency, a loading of of 115% of 125% might be might be accepted, during a double contingency, a loading of

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Traditional Reliability Engineering Tools and Their Limitations

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Transformer Loading Limits and Voltage Criteria Table 9.1 Transfonner Criteria for Various Contingency Contingency Situations Used By Four Electric Electric Utilities in the U.S. Utility Number

Voltage

Base

1

.97 - 1.03 .97-1 .03

83%

.96 - 1.04 .04 .96-1

125%

.95 -1.05 .95-1 .05

133%

2

.96 - 1.05 .96-1 .05

75%

.95 - 1.07 .95-1 .07

115%

.95 - 1.05 .95-1 .05

125%

3

.97 - 1.05 .97-1 .05

90%

.96-1.05 .96-1 .05

135%

.94-1 .94 - 1.05 .05

166%

4

.95 - 1.04 .95-1 .04

90%

.94 - 1.05 .94-1 .05

135%

.94 - 1.06 .94-1 .06

166%

Loading Loading

Voltage

N-l Loading

Voltage

N-2 Loading Loading

9.1 lists the voltage and loading requirements for several accepted. Table 9.1 utilities in the U.S. as a function of of contingency situation. Application Application of N-1 N-1 using a Computer Computer Program

of really powerful digital As originally conceived, prior to the existence of computers for power system studies, this process was done with an analog computer. Each case was set up and studied on an individual basis by the utility's power system planners, by adjusting settings and patch-cord connections on the analog computer. For this reason, initially initially (1950s) often often only the 100 or so most important components (out of of several thousand in a large power system) could be studied for contingency outage. However, beginning in the late 1960s, programs on digital computers were developed which would automatically check all single contingencies in the system [Daniels]. These programs became a staple of of utility for system planning. A modem modern contingency analysis program works along the lines shown in Figure 9.1. It is built around a load-flow program - a digital program that takes a data set describing the power system and the loads it is to serve, and solves a flows, and power set of of simultaneous equations to determine the voltages, flows, factors that can be expected in that system. In an automatic contingency analysis program, the basic load flow program is augmented with an outer loop, which automatically cycles through this power system data set, removing each of equipment and line, in turn, tum, and solving the load flow analysis for that unit of particularly contingency case. For each such case, the program checks the results of of that contingency case and reports any loadings or voltages that are out of acceptable range. It then

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Base Case Case N Components

Satisfies Base Case Criteria? Yes For all N components n = 11 to to N — fc-

1r Remove component n from from database database and and resolve load flow

Satisfies

Report "no problem"

N ·1 Criteria? Yes

Add component and problem to output report

Figure 9.1 9.1 Basic approach approach behind the N-J N-l contingency planning approach. approach. Engineering studies of the system and outage each one, one, studies cycle through all components of studying what loadings and voltages voltages would result. The system is considered to meet "N-J" cases result in no out-of-range loadings or "N-l" criterion when all such contingency cases voltages.

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"restores" that outaged outaged component in the database, removes the next unit in turn, and runs that contingency contingency case, cycling through all components in the system. A system plan was considered acceptable when this type of of evaluation showed that no voltage and loading standards violations would occur in every one of of these instances of single contingencies. Figure 9.1 9.1 illustrates this basic approach.

A Successful Method in the Mid and Late 20th Century Century From the early 1960s through the early 1990s, the vast majority of of different different electric utilities applied this basic approach, with a number of slight variations here and there. Typically, a utility would design its system to completely meet N-l criterion (the system can perform despite the loss of of anyone any one component) and to meet certain N-2 criteria (a set of of specific two-failure conditions, which are thought to be critical enough to engineer engineer to tolerate). Systems designed using this approach produced satisfactory performance at costs not considered unreasonable. Supposedly Good Systems Begin Giving Bad Results

In the late 1990s and early 'OOs, the operating record of of large electric utilities in of the United States revealed increasing problems in maintaining reliability of service to their customers. During the peak periods in the summers of of 1998 and N-1 criterion 1999 a number of power systems that fully met the traditional N-l experienced experienced widespread widespread outages of their power delivery systems. Table 9.2 lists only some of of the more significant events in 1999, as identified by the U.S. Department of of Energy. In particular, the CornEd ComEd system's (Chicago) inability to provide service was disturbing, because that system was designed to N-l N-l

Table 9.2 Major Major System Outages Identified By US DOE in 1999 Area

When

Interruption

Cause

Power Delivery? Aging Infra?

New England Jun 7-8

shortage Wholesale generation shortage

Chicago Chicago

Aug 12

Multiple power delivery failures

x X

Jul 30

Multiple power delivery failures

x X

x X

New York

Ju16-7 Jul 6-7

Multiple power delivery failures

x X

x X

Long Island

Ju13-8 Jul 3-8

Power Power delivery and grid problems

x X

x X

Mid Atlantic

July 6-19 & grid problems 6- 19 Wholesale generation &

N. New Jersey Jul 5 - 8

Multiple power delivery delivery failures

So.-Central USJul23 US Jul 23

Wholesale generation shortages

Delmarva

Wholesale grid and generation shortages

Jul 6 Jul6

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x X

x X x X

x X x X

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standards and even met an N—2 N-2 and N—3 N-3 criterion in some places. There were a sufficient number of these events to make it clear ComEd was not an isolated or sufficient atypical situation [U.S. DOE, 2000]. Perhaps more significantly, the level of of reliability-related reliability-related problems on U.S. systems had been growing for several years prior to 1999. Based on analysis of of industry survey data, the authors first noticed the trend in 1994. While at that time there were few widespread customer outage events, throughout the 1990s 1990s of operating emergencies, there was a growing "background noise level" of emergencies, equipment overloads, and frequent if small customer interruptions on many utility systems. Even without the major events cataloged in the DOE report of customer service quality was falling in many (Table 9.2) the industry's record of regards prior to 1999. 9.3 LIMITATIONS OF N-1 N-1 METHODOLOGY

This section explains the limitations that N-1-power N-l-power system planning and design utilization factor, lean techniques encounter when applied to modem modern (high utilization margin) power systems. Contingency-based Contingency-based planning, like all engineering methods, is based on certain assumptions, uses approximations in key areas, and of application. application. And like other has limitations in its accuracy and range of engineering engineering methods, if applied to situations within which these assumptions, approximations, and limitations limitations do not seriously hinder its accuracy and effectiveness, the method provides very good, dependable results. But if applied outside that range, its results may prove undependable, and the system plan may provide unsatisfactory performance. of the 20th century, the electric utility Gradually, throughout the last quarter of industry changed how it used and operated its power systems. Some of of those changes meant that their systems operated in states and in situations for which N-l approach was not completely valid. The resulting incompatibility of the N-1 of method versus use of of the reliability of the resulting system contributed to many of problems experienced experienced by utilities. Of necessity, in order to fit within the space available in this book, this Of chapter's discussion is somewhat shorter and contains certain simplifications simplifications chapter's with respect to a "real power system." This abridging has been made in order to quickly get to the heart of of the shorten the discussion, allowing the reader to quickly diminish distractions from the main theme due to secondary secondary and matter, and to diminish factors. Therefore, this discussion makes the following "assumptions" tertiary factors. simplifications with respect to the system being discussed as an example here: or simplifications •

All All equipment of a specific specific type will will be of the same capacity; capacity; e.g., all substation transformers transformers are the same capacity.



All All equipment is is loaded to to the the same peak level, level, that being the

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peak. average utilization ratio for the system at peak:. •

All All equipment units units of anyone any one type (e.g., (e.g., all all substation substation transformers) have the same failure rate.

The reader familiar with power systems will recognize all three complicate power as great simplifications of the many details that complicate system planning and reliability engineering. However, real-world variations from these assumptions do not diminish the limitations and phenomena that will be discussed in the next few pages. In fact they slightly exacerbate them: these complexities generally worsen the problems explained here. Summary of the Problem Problem Overall Summary criteria assure power system planners and engineers engineers N-l methods and the N-l criteria feasible way to back up every unit in the system, should it fail. that there is some feasible However, they make no assessment of the following: following: How likely is is it that such backup will will be needed? • How How reasonable is is the the feasible plan for for each contingency situation • How or is the planner actually building a "house of cards" by expected "too many things to go right" once one thing has gone wrong? "too How much stress might the the system be be under during such • How contingency situations, and the long-term implications for both equipment life and operating policy? How often will conditions occur which cannot be backed up up (e.g., (e.g., • How failures) and how bad could the situation become when that multiple failures) is the case? case? N-l criteria may be far less reliable than As a result, systems that meet the N-I needed, even though the N-I N-l criteria "guarantees" there is a way to back up every unit in the system. This is much more likely to happen in modem modern power systems than it was in traditional, regulated power systems, due to changes in utilization and design made in the period period 1990-2000, and the more volatile operating environment of de-regulation. Utilization Ratio Sensitivity

The major culprit that led to problems that "N-l "N-l could not see" see" was an increase in the typical equipment utilization utilization ratio used throughout the industry. industry. When it is raised, as it was during the 1980s 1980s and 1990s, an N-l N-l compliant system, which

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previously gave good service, may no longer give satisfactory reliability of of service, even if it continues to meet the N-l criterion. Similarly, Similarly, power systems N-l criterion and intended to operate at higher than designed using the N-l traditional levels of of equipment loading are very likely to have higher customer interruption rates than expected. There is nothing nothing inherently inherently wrong with this trend to higher loading levels. In financially efficient, which fact it is desirable because it seeks to make the utility financially is potentially potentially beneficial to both stockholders and customers. A power system that operates at 83% or 90% or even 100% utilization of of equipment at peak can be designed to operate reliably, reliably, but something beyond N-l N-l methodology is reliability. required to assure that it will provide good customer service reliability.

necessary but not a sufficient sufficient criterion N-1 is a necessary Due to the success that N-l N-l methods had throughout the 1960s, 70s and 80s, of service, most producing power system designs that provided good reliability of utilities treated the N-l power system planners and most electric utilities N-l criteria as a necessary and sufficient sufficient criteria. Design a system to meet this criterion and it factors, while N-l N-l criterion was, by definition, reliable. But at higher utilization factors, is still a necessary necessary criterion, it alone is not sufficient sufficient to assure good quality of of of utilization service. The reasons for this change in reliability as a function of utilization ratio are far subtler than is typically recognized. This section will review the N-J has when applied to high-utilization-ratio high-utilization-ratio systems and limitations that N-l explain what happens, and why. The authors want to make clear that they of all the industry'S industry's definitely are not labeling high utilization utilization ratios as the cause of of applied problems. Rather, it is the incompatibility incompatibility between traditional ways of the N-J N-l criterion, criterion, and the way these systems operate, that created the problem. Traditional Traditional utilization utilization levels

In the 1960s through early 1980s, electric utilities typically loaded key equipment such as substation power transformers and downtown subtransmission cables to only about 2/3 or a little more (typically about 66%) of their capacity, even during peak periods. The remaining capacity was kept as an "operating reserve" or "contingency "contingency margin." Engineers and planners at N-l and other distribution utilities designed their power systems using the N-l criteria, while counting on this margin. In such systems, when a transformer or line failed, it required one neighboring transformer of of equal capacity, perhaps already loaded to up to 66%, to be available to pick up its load. Depending on how close the system was to of the outage, this unit might have to accept as much as peak demand at the time of 133% of of its normal load (its normal 66% of of rating and its neighbors 66%, too). tolerable for brief brief period. Power equipment can be run Such overloading was tolerable

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•§100 ~ 100 (0 IV

E CI) C .:Jt:

:8

0. a.

..

'0

cCI) 50 ~

CI) 0)

a.

"~ ..J

0 8760

0 Per Year Hours P&r Year Load Level Is Exceeded

Figure 9.2 Annual load duration curve for a utility system. Risk periods for high Figure of a traditional power system occurs occurs only 10% of of the time (shaded (shaded contingency loading of area). See text for details.

brief periods without significant damage, if this is not done too above rating for brief often. And in fact it was unlikely unlikely that the loading would be as high as 133%, because occurred during a peak load period. because that would only occur if the outage occurred of peak demand would overloads occur Only when loading was above 75% that of of peak, one transformer (75% x 66% = 50%, so at any load level below 75% of of two without going over 100% of of its rating). In the system can handle the load of whose load duration curve is shown in Figure 9.2 (a typical US utility system), of the year. As a result, it was (and still is) such load levels occur only 10% of very likely that when equipment failures occur, they will occur at some time when loading is not near peak and hence stress on the equipment picking up the outaged units load was not unduly high. outaged Higher utilization rates Higher Beginning in the 1980s and increasingly in the 1990s, 1990s, utilities pushed Beginning pushed equipment utilization upwards to where in some systems the average substation transformer was loaded to 83% of of its rating during peak periods. As was discussed discussed in of this system, utilization rates can average close to Chapter 8, in aging areas of 100% under "normal" peak conditions. Table 9.3 shows industry averages averages

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loading guidelines guidelines for normal and contingency loading Table 9.3 Design loading Average maximum peak load as planned, Average planned, under under normal conditions, conditions, as a percent of of nameplate thermal rating. of Nameplate rating. Percent of 1998 1988 1979 1970 > 1,000,000 customers 75 Among utilities with with> 85 70 64 Among utilities with 500,000 500,000 and 1,000,000 75 70 65 85 with < 500,000 customers Among utilities with 75 70 70 65 In rural areas In suburban suburban areas In urban areas

70 85 90

65 80 82

65 75 75

62 67 72

Maximum planned peak load expected under contingency conditions conditions (at least four hours duration) Percent of duration) of Nameplate 1998 1988 1979 1970 Among utilities with with> > 1,000,000 customers Among utilities with 500,000 and 1,000,000 Among utilities with < 500,000 customers customers

145 140 135

140 135 135 130

135 130 130

133 127 127

obtained for a comprehensive survey of loading practices across the industry. industry.l1 The engineers in charge of of these higher-utilization rate power systems knew, and in fact, planned for, for, their system to accommodate these higher utilization rates in several ways. To begin, these higher utilization rates required considerable augmentation of of system configuration and switching. In a system considerable of only 66% at peak, each transformer and line required loaded to an average of one neighboring unit to "stand by" to pick up its outage. This meant, for two-transformer substations, there had to be buswork and example, that in each two-transformer switches) configured so that if one of the units failed, failed, the switchgear (breakers, switches) Alternately, the load at the substation other could automatically pick up its load. Alternately, partially transferred to neighboring substations (onto their had to be partially transformers) through the feeder system, as will be discussed in section 9.4. Usually, some combination of of stronger substation and sub-transmission-Ievel sub-transmission-level buswork and switching flexibility, and increased reliance on feeder-level transfers was used.

1

From Electric Power Distribution Practices and and Performance Performance in in North America - 1998 1998 From ("The Benchmark Report" by H. L. Willis and J. J. Burke, ABB Power T&D Company, ("The Raleigh, NC. "Design loading" as used here, refers to the peak load on a transformer, above which which it is considered so highly loaded that it should be upgraded in capacity, capacity, or transferred elsewhere. elsewhere. "Emergency rating" rating" refers to the maximum load permitted load transferred permitted to on the substation substation during an equipment equipment outage or excessive load contingency. contingency. 1

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Those plans for these higher-utilization systems were created using N-I N-l methods, which "took into account" those higher utilization rates in their analysis. These N-I N-l Analysis applications assured that there was a way to back up every unit in the system, should it fail. The system plans developed as a result fully met the full N-l N-l criteria everywhere, and N-2 N-2 criteria in critical places, even though they were operating at these higher utilization rates. Thus, these systems did have well-engineered contingency capability. The equipment was there and it would, and did, work as intended. Any problems lay elsewhere. Looking at N-1 's Limitations N-1's Limitations

In order to understand where the problem with N-I N-l criterion application lies, it N-l criterion is important to first understand that a power system that meets the N-I can and routinely does operate with more than one unit of of of equipment out of service. Consider a power system that has 10,000 elements in it, each with an outage expectation of of..16% 16% - a value lower than one one would ever expect on on a real power system. One can expect that on average, about 16 16 elements will be out at any one time. Yet the system will usually continue to operate without problems. anyone The reason is that the N-I N-l criteria has guaranteed guaranteed that there is a backup for every one of of these failed units, as shown in Figure 9.3. The system will fail to serve its entire load only if if two of of these multiple outages occur among neighboring equipment. For example, if if a transformer and the transformer designated to back it up both fail at the same time, as shown in If a unit, and its backup, are both out, then, and only then, will a Figure 9.4. If service interruption occur. Contingency Contingency support neighborhood

"Neighboring "Neighboring equipment" as used in the paragraph paragraph above means the equipment in the vicinity of of a unit that is part of the contingency support for its outage. This can be more accurately described as its contingency support support neighborhood: the portion of of the system that includes all equipment that is part of of the planned contingency support for the unit's outage. For a substation power transformer, this might include at least one neighboring transformer (usually at the same substation) which would provide capacity margin during its outage, along with portions of of the high-side and low-side buswork and switchgear, which would non-standard configuration during its outage. operate in a non-standard outage. Figure 9.5 illustrates this concept, showing several "contingency support neighborhoods" as in the example system used in Figures 9.3 and 9.4. As stated neighborhoods" in the introduction to this section, this discussion simplifies the real world somewhat. Here, every unit is the same size and contingency support is always grouped exclusively in sets of neighbors. Actual design is more complicated, but the complications do not make any substantial net impact this discussion.

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286

- 1,

r--

,,

Figure 9.3 One-line One-line diagram for a small part of of a large power system. Four equipment outages are shown, indicated indicated by an X, two transformers, one high-side high-side bus, and one subneighboring unit (shaded) that has picked up transmission line. Each outaged unit has a neighboring its load: the N-l criteria criteria assured that this was the case. The system continues to operate smoothly because no two of of the outages occur close enough to one another.

--, I

J

Figure 9.4 One set of of dual failures in the same contingency support neighborhood, as Figure illustrated here with the failure of of two neighboring transformers (each was the designated designated backup for the other), will lead to interruption interruption of of service to consumers. Here, the shaded circle indicates indicates the rough rough area of of the system that would be without power.

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Figure 9.S 9.5 Every unit in the system has a "contingency "contingency support neighborhood" neighborhood" that includes all the equipment that provides contingency support for the unit. unit. Shown here are two transformers (shaded) along with their neighborhoods (circled). Equipment in a neighborhood provides contingency margin (capacity) as well as connectivity flexibility (switching, flow capability) capability) during during the outage ofthat of that unit.

Problems in this N-I N-l system that lead to customer outages occur only when two or more equipment units fail simultaneously within one contingency support neighborhood. Such a "double failure" does not have to be among just the unit and its like-type of of support unit, i.e., the failure of of both transformers at a twotransformer substation. Failures of one transformer and a line, a breaker, or a bus needed to support the contingency re-configuration of of the system to support its outage can also lead to a failure to maintain service. Still, such occurrences are very rare. While there are perhaps 10 10 to 15 units out of service in a system of 10,000 elements, it is most likely that they are scattered scattered singly throughout the of system. The likelihood that two are concentrated in one-minute neighborhood is remote. Traditional Traditional power power systems had "small" contingency contingency support neighborhoods

In traditional power delivery systems, those whose utilization ratio for power transformers transformers and sub-transmission lines was nominally nominally targeted to be about 66% of equipment rating during normal (design) peak conditions, the contingency of support neighborhood for any unit of of equipment was small. As discussed

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earlier, every unit in the system needed one backup unit of A of like size. A 32 MV MVA transformer would be loaded to 22.5 MVA (66%) at peak. Ifit If it failed, its partner at a substation, also already serving 21 MV A, would pick up its load too, briefly MVA, A) loading so that all demand was served. Therefore, running at 133% (45 MV MVA) the contingency support neighborhood for both units was a small locality that included the other transformer and the various switchgear switchgear and buswork needed to connect the two to the other's load during a contingency. Systems with high utilization utilization rates have Systems larger larger contingency contingency support support neighborhoods neighborhoods Suppose that the area of of the power system being considered has 88.5% loadings of 66%. In that case, when any transformer fails, on all transformers, instead of and if the utility is to keep within a 133% overload limit, a failed unit's load has of the to be spread over two neighboring transformers, not just one. The size of "contingency support neighborhood" for each unit in the system has increased "contingency by a factor of of fifty percent. Previously it included one neighboring transformer, now it includes two. More importantly, the probability that an outage will occur among the designated designated support units for each transformer is double what it was in the system loaded to only 66%. Previously, whenever a transformer failed, there was only of good service. Now, if either of one unit whose failure stood in the way of of its two designated support units fails, an interruption of of service to the utility's customers will occur. Two possible failures, each as likely to occur as the one failure that could have taken out the 66% loading system Thus, in a system where utilization rate has been pushed upward, every contingency support neighborhood is proportionally larger, and thus a greater target for trouble to occur: There is more exposure to "simultaneous "simultaneous outages." In a system loaded to 66%, there is only one major target. Failure to serve the specific neighbor neighbor designated as load occurs only if a unit of equipment and one specific its contingency support are both out of of service. In a system or area of of a system if a unit and either one of loaded to 88.5%, it occurs if of two neighbors is out. In an area of of a system loaded to over 100%, (as some aging areas are) it occurs anyone whenever the unit and any one of of three designated neighbors is out (Figure 9.6). Basically, the whole problem boils down to this: the contingency support neighborhoods are larger. But there are still "N-I" "N-l" neighborhoods: each can tolerate only one equipment equipment outage and still fully meet their required ability to serve demand. A second outage will very likely lead to interruption of of service to some customers. In these larger neighborhoods, there are more targets for hit. "Trouble" that leads to an inability to serve customer that second outage to hit. demand is more likely to occur. The analysis below estimates the relative likelihood that this occurs in example systems loaded to different different levels.

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Figure Figure 9.6 At 100% loading, each transformer from Figure 9.5 needs three nearby units to cover its load, expanding the "contingency "contingency support neighborhood" neighborhood" involved. See text for details.

A system as discussed earlier, with "10,000 major elements." elements." might contain 1,200 substation transformers. Assuming that the outage rate for them is .25%, this means: 1.

In a 66% utilization system, there are 600 two-transformer two-transformer contingency support neighborhoods. Failure to serve the load occurs only if both transformers transformers of of this pair fail. That is:

.00252 = .000625 .000625 • Failure probability = .0025 Hours per year = .000625 x 8760 hours/year x 600 600 pairs = 32.9 32.9 • Hours hours/year. 2.

In an 88.5% utilization system, with three-transformer contingency if all three support neighborhoods, failure to serve the load occurs only if or any two transformers of of this triplet fail. Over the whole system, annually, that is probability == .0025 .00253 + 3x(.0025 3x(.002522x(1 x(l - .0025)) • Failure probability .00001871872 .00001871872 400 triplets triplets == 65.6 65.6 • Hours per year == .00001871872 x 8760 hours x 400 hours/year.

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3. In a 100% utilization system, with four-transformer contingency support neighborhoods, failure to serve the load occurs if if all four, four, any three, or any of this triplet triplet fail. Over the whole system, annually, that two transformers of

is IS 4

2

Failure probability = .0025 4 + 4x(.0025 4x(.0025 3Jx(l - .0025)+6x(.0025 .0025)+6x(.0025z)x(1 )x(l 2 .0025)2= .0025) = .000037375 .000037375 Hours per year = .000037375 .000037375 x 8760 hours x 300 quadrals == 98.22 hours/year

By comparison comparison to a traditionally loaded system, a power power system at a higher utilization rate is two to three times as likely to experience a situation where a pattern of of equipment equipment outages fall outside of of the N-I N-l criterion. criterion. For example, one of of the "N-2" "N-2" situations that might lead to an interruption ofload. of load. Systems run at higher equipment utilization rates are more likely to experience experience events that could put them in jeopardy of being unable to serve all customer customer loads. N-I N-l analysis does not measure or evaluate this in any manner. N-l criterion assures planners and engineers that a feasible way to N-l equipment outage has been provided. It does nothing to handle every equipment address how how often often situations outside of that context - i.e. those that will lead to unacceptable service quality, might occur. High Utilization Coupled With Aging System System Greatly Increased Increased Service Service Equipment Leads to Greatly Problems

effect that aging has on equipment equipment failure failure rates. In Chapter 7 discussed the effect aging areas of of a power power system, the failure failure rate for equipment equipment is three to five times that of of normal areas of of the system. Coupled with the high utilization rates common in these aging areas and the result is a ten to one or slightly worse common of customer service interruptions due to equipment outages. 2 incidence of

2 2 Here the authors authors will bring in a real world factor. Chapter 8 discussed why utilization A rates are usually above system average average in aging aging infrastructure areas of of the system. A where the average has gone from 66% to 88.5% may have seen only a modest system where newer areas of increases increase in the utilization rate for equipment in newer of the system, while increases in aging areas make up for those below-average below-average statistics. Thus, the aging aging part of of the much higher utilization than other parts. customer service problems parts. Its customer problems stand system has much of the higher failure rate rate in this area, and the higher likelihood that out both because of outages lead to customer interruptions. As a result aging areas often have a customer interruption rate up to twelve times that of of newer areas of of the system.

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Increased High-Stress Levels and Periods Increased High-Stress The situation is slightly worse than the perspective developed above when one looks at the stress put on the system's equipment, and the portion of of the year that the system is likely to see: high- and medium stress events due to equipment outages. In a 66% utilization system, every transformer is paired with one other: whenever the unit it is backing up fails, it must support the load of whenever of two transformers. Given the transformer failure rate of of .0025%, this means each transformer can expect to have its partner our of of service and thus be in this "contingency "contingency support mode" about 22 hours (.0025 x 8760 hours) per year. of the time, this means that Given that the system is at peak demand about 10% of a transformer can expect about two hours of severe loading time per year. When utilization ratio is 88.5%, each transformer is partnered with two other units: failure of of either one will put it in a contingency contingency support mode. Thus, neglecting the slight amount of of time when both its partners are out of of service, (and thus customer service in interrupted), the amount oftime of time it can expect to be in this mode is twice what it was in the 66.5% system: or about 44 hours, 4.4 of of that will be high stress. Similarly, in 100% utilization, each transformer will see about 66 and 6.6 contingency support and high-stress hours period year. Stress put put on system equipment is much higher in high utilization systems.

"Low standards" standards" Operating Hours are Increased Increased "Low It is also worth considering that standards on loading, voltage regulation and

other operating factors are relaxed during contingency situations (see section 9.2). Since the amount of time that the system spends in these "medium stress times" is greater in high utilization systems, which means that the distribution in "sub-standard" situations - twice is too much if the system spends more time in utilization rate is 88.5%, three times as much if if utilization is 100%. The Result: Lack of Dependability as Sole Planning Tools

The limitations discussed above can be partly accommodated by modifications to the traditional approaches and changes in N-I N-l criteria application. But the overall result is that resource requirements (both human and computer) rise dramatically, and the methods become both unwieldy and more sensitive to assumptions and other limitations not covered here. The bottom line is that N-I N-l and N-2 N—2 contingency-enumeration contingency-enumeration methods were, and still are, sound engineering methods, but ones with a high sensitivity to planning and operating conditions that are more common today than in the mid-1960s when these methods came into prominence as design tools. These limitations reduce the

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292

....

— Required 10,000 , - - - - - - - " - - '......."""TTITTTIT1Tnnn• . Required performance: performance: 10,00030 minutes per year SAIDI SAlOl against aa load curve with with peak peak of of 10,350 10,350 MW MW and 56% annual load factor.

JIj

CD

' Deficiency range: range: area of of performance expected expected based on N - 11 analysis, that is really not there. thers.

~

'"

U

~

.3

9,500 Capability as — _ -:---. estimated by N - 11 methods

iii

'"

CII Q. a. "C

03 co oO ...J

o~----------------------------------------

o

8760

Hours Per Year Load Level Is Exceeded

Figure 9.9 When load exceeds forecast, it usually usually does so no only during peak periods but for an entire season (summer, winter). Shown above are forecast vs. actual annual for 1998. As a result of the load duration curves for a utility in the mid - United States, for higher temperature summer weather, peak load was about 3.3% higher, but the period of of high stress for the system was 30% more for the entire year. The system operated operated in high-stress modes for more than twice as many hours during the summer as expected.

Spatial forecasting forecasting Spatial A great deal of of power delivery planning is about where equipment and facilities should be placed. It does little good to add substation capacity in the wrong substation area, or to bolster feeder capacity in the wrong feeder area. A spatial forecast, which associates electric load and growth with location, is typically used to associate electric load growth with location, so that planners know both where and how much load growth to anticipate. anticipate. Figure 9.10 displays displays a longterm spatial forecast. of methods are in use for spatial forecasting, from simple trending A number of of weather-adjusted substation and feeder peak load methods (extrapolation of histories) to quite comprehensive simulations involving analysis and projection of changes in zoning, economic economic development, land-use, and customer end usage of of electricity. Results vary greatly depending on method and resources used, but of engineering methods exist to both determine the most appropriate methods and engineering forecast characteristics needed for any utility application, and to evaluate the efficacy of of a forecast. forecast. The most important factor is that a utility employs some efficacy

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201 20111 WINTER PEAK 3 442M VA 3442 MVA

1991 WINTER PEAK 2310MVA 2310 MVA

Ten miles

Figure 9.10 9.10 Maps of of peak annual demand for electricity electricity in a major American city, showing the expected growth in demand during during a 20 year period. Growth in some parts of the urban core increases considerably, but in addition, addition, electric load spreads into of population. currently vacant areas as new suburbs are built to accommodate an expanded population. Forecasts like this, done for two-, four- and similar Forecasts similar periods out to twenty years, set the requirements for both short- and long-range power delivery system planning.

Percent of of Utilities Utilities in North America Using Some Type of of Formally Table 9.4 Percent Recognized Spatial or Small Area Load Forecasting Method Recognized SEatial Forecasting Method

1998

1992

1988

1979

45

75

70

35

Among utilities with 500,000 500,000 - 1,000,000 customers 50

70

65

30

12

15

15

10

Among utilities with > 1,000,000 customers utilities with> Among utilities < 500,000 customers

legitimate means of of studying and projecting load on a detailed enough locationbasis to support its planning needs. Traditionally, considerable labor and Traditionally, good spatial forecasting required both considerable above-average engineering skills and was considered a "high-expertise" "high-expertise" function traditional within state of of the art distribution planning methods. The best traditional methods worked very well but had rather high labor and skill costs methods

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[Willis and cut and Northcote Green - 1983, Engel et et al - 1996]. Many utilities cut back on both the quality of of the technique used and the effort effort devoted to data collection and forecasting study, when they downsized professional professional staffs during utilities using the the 1990s. Table 9.4 illustrates the reduction the number of utilities best class (simulation-based) spatial forecast methodology, but does not reflect reductions in the data or time put into the forecasting effort. As a result, at a time when spatial forecasting needs are at an all time high (see below), the of local-area forecasting done at many utilities deteriorated sharply. 5 quality of In the very late 1990s, new forecasting forecasting methods were developed that reduce labor and skill requirements considerably, but these have limited availability and are not widely used [Brown et ai, al, 1999]. However, this means methods that can provide the information information needed within within reasonable labor and skill limits limits are available to the industry. Impact Impact of of spatial spatial forecast errors on reliability reliability

In some manner, every T &0 plan includes a spatial forecast, for the total load T&D growth allocated in some manner among the various parts of of the system. system. Classically, the viewpoint on forecast sensitivity of of T&O T&D systems has been that if the spatial element of if of the forecast is done poorly, the result is a very poor use of of capital. A projection of of the wrong locations for future load growth identifies reinforced. Capital incorrectly those portions of of the system that need to be reinforced. additions are made less effectively effectively than possible. But in addition, a large effect effect of of poor spatial forecasting is a loss of of contingency capability. Normally a power system designed based upon a mildly incorrect spatial forecast (i.e., one pattern of of ":where load is") will suffer suffer from less than the planned contingency withstanding capability (i.e., provide less reliability in service) than expected. It will operate well enough during times when "everything "everything is going well" but suffer from problems that are both more serious and take longer to fix than expected during contingencies. Essentially the poor forecast "uses up" the contingency capability built into the system [Willis and Tram, 1984]. Systems with high utilization utilization ratios are more sensitive to this degradation of of contingency planning due to spatial forecasting errors. Although subtle, the effect effect is best described this way: The contingency neighborhoods described earlier increase in size as a result of of the higher utilization ratios used (Figures 9.5 and 9.6. While it may seem that this makes the planning less in need of of detailed spatial forecasts (there are are fewer "units" - contingency support support on average far is true. neighborhoods - and and they are are on far larger), the opposite is of load within each Contingency capability is very sensitive to the allocation of forecasting were identified as a major Load forecasting problems related to local area forecasting contributing problem in six of of events (Table 9.2) investigated by DOE's P.O.S.T. report.

5

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support neighborhood. The analysis given earlier assumed the load in each neighborhood was evenly split among units in that group: if if it is even slightly unbalanced, the system's contingency capability is greatly degraded. The forecast of of where load is within each contingency support neighborhood is efficient allocation of of loads to equipment critical, so that proper, operationally efficient of poor spatial forecasting (and planning) and a can be arranged. One sure sign of system with less contingency withstand capability than it could have, is that considerable operational adjustment to loading patterns (load balancing) has been done, by altering switching and feeder loading. Again, as with poor weather normalization, this "uses up" the contingency capability of the system, something in very short supply in aging areas of of the system. SAID! SAIDI increases.

Interconnection Complexity Complexity In the slightly simplified power systems used as examples earlier in this chapter, the small contingency support neighborhoods needed at 66% loading required interconnection with only two neighboring units assured success without overload during N-l conditions. But at higher utilization ratios, contingency of mutually supporting support neighborhoods grew in size and number of components. Interconnection of of more equipment, into a scheme where it could support one another during contingencies, was necessary for success of the contingency plans. In aging areas or where for other reasons planners and engineers have of equipment, there is a requirement for an even accepted near 100% utilization of stronger and more widespread interconnection. Everywhere in a high-utilization of its N units must have a strong-enough electrical tie to a wider system, each of of equipment around it, to support its outage. neighborhood of At higher equipment utilization rates, the importance of of configuration and operating flexibility in the design of the system becomes more critical to reliability. of

analysis of Traditional contingency-based study methods can deal with the analysis of of support around every one of these issues relating to the wider neighborhood of of the N units in the system, and its great complexity. They can determine if the of neighbors are there, if they have enough margin of required number of of capacity to accept the load without overloads, and if if the system's electrical configuration makes it possible for them to pick up the demand that was being served by the modern N-l failed unit. Basically, modem N-l methods can and will determine if the failure of of each unit in the system is "covered" by some plausible means to handle its failure and still provide service. Again, N-l N-I methods do not work with probabilities nor determine the system's sensitivity to multiple failures, so they cannot determine the failure sensitivity or failure likelihood likelihood of of these complicated interconnected schemes.

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At higher utilization ratios, complexity of the contingency backup cases has if a particular contingency backup plan is really increased. Determining Determining if feasible, if if it is really connected with sufficient sufficient strength to survive the likely failure states, or if it depends on too much equipment operating in exactly the wrong way, is something N-l methods methods do not fully address. Configuration needs to be studied from a probabilistic basis - is is this entire scheme of rollover and re-switching problem') re-switching likely to really solve the problem? 9.5 THE PROBLEM IS NOT HIGH UTILIZATION RATES RATES A point the authors want to stress again is that high equipment utilization is not the cause of of poor reliability in aging infrastructure infrastructure areas of of a power system. It is possible to design and operate power systems that have very high (e.g., 100%) 100%) utilization factors and provide very high levels of of service reliability. This is accomplished by designing a system with the configuration to spread contingency burden among mUltiple equipment units, with the flexibility to react among multiple to multiple contingencies, and that can apply capacity well in all the situations most most likely to develop. Such designs require detailed analysis of of capacity, configuration, configuration flexibility, failure probabilities, probabilities, and the interaction of of all these variables. This does not mean that every power system should be built with high equipment utilization. The authors are not "taking sides" on the issue of of utilization rate, because it has no single answer. Equipment utilization is only one factor in the design of of a power system. In some cases, the best way to "buy" "buy" reliability along with satisfactory electrical (power flow) performance is to use capacity -— to build a system with low utilization utilization ratios. But in other cases, particularly where the cost of of capacity is very high (as it is in many aging infrastructure areas), good performance comes from using the equipment to its utmost. Achieving high reliability of of service even in these situations where equipment equipment is highly stressed stressed and contingency margins are small or non-existent requires using configuration and interconnection flexibility flexibility in an artful manner. The key point is that traditional planning tools are incompatible with these needs. They cannot provide dependable analysis of, nor serve as good good guides for such engineering. They lead to designs with necessary and sufficient qualities for good reliability only if if the capacity margin is used to purchase reliability. They do not identify identify weak points in a system nor provide an indication of of how and where solutions to these problems may be pursued through changes in the design of the system. Traditional Traditional planning tools are for planning reliability reliability in aging aging inFastructure partly undependable partly undependable for infrastructure and other "high stress stress"" areas of of a power system. system.

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SUMMARY AND CONCLUSION 9.6 SUMMARY Traditional Tools Have Shortcomings Shortcomings Respect to Modern Modern Needs Needs With Respect

of the problems faced by a utility owner/operator owner/operator of of an aging power T&D Many of infrastructure are compounded by the fact that the tools being used by its planners and engineers cannot directly address one vital aspect of of the required performance: reliability. reliability. Traditionally, reliability was addressed in power system design by engineering contingency contingency backup capability into the system: system: system of equipment could be completely backed up should it fail. every major unit of engineer a system based This was termed the "N-l" criterion and methods that engineer on this criterion were often referred to as "N-I" "N-l" or "N-X" methods. Such methods addressed a key and necessary quality for reliability: there must be a feasible way to do without every unit in the system, some way of of switching around it during its outage and/or picking up the burden it was serving during its outage. Realistically, Realistically, no power system can be expected to provide reliable service to its energy consumers unless it possesses possesses this necessary qualification of having complete N-l N-I contingency capability. But through many years of use during periods when equipment loading of equipment were lower than is typical in the 1990s and 2000s, the levels of power N-I criterion as a necessary necessary and sufficient. For power industry came to view N-l power systems with roughly a 33% redundancy (contingency margin), the criterion is effectively effectively a necessary necessary and sufficient sufficient criterion to assure reasonable of reliability. However, when a power system is pushed to higher levels levels of of N-I is still a necessary necessary criterion, but no of equipment utilization efficiency, N-l longer sufficient sufficient to assure satisfactory levels of of reliability. of the N-I Basically, the shortcoming of N-l criterion, as well as engineering engineering methods based upon it, is that they do not "see" "see" (respond to, identifY identify problems with, or measure) anything with respect to reliability of of service except the "yes/no" satisfaction of this one criterion. Therefore, they cannot alert engineers to a flaw in the design of a power system with respect respect to its reliability, due to either the likelihood that events may get worse than the system can stand. "Yes, "Yes, you have a feasible backup plan, but for this system it is very likely that while of equipment is outaged, something else will go wrong, too." this unit of too." Or, because some parts of of the system are key elements for reliability of of the system "important enough" that they need more around them, to the extent that they are "important reliability built into their design. "This unit is more important than you realized: achieve." A second backup is really needed for the reliability level you want to achieve." Furthermore, they cannot provide quantitative guidance to planners and effective but engineers on what to fix and how to fix it in a satisfactorily effective economical manner.

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A Deeper Problem, Too

Finally, there is a more subtle but perhaps more fundamental fundamental problem associated associated with the use of of N-l, one that is difficult difficult to fully demonstrate in a textbook, but nonetheless real. N-l nonetheless N- I engineering procedures solve reliability problems by using capacity: capacity: It is a criterion and method that uses contingency margin as the means to achieve reliability. reliability. This is partly the nature of of the criterion and the tool, but the way way of thinking thinking - built for for the but also the the fault of the the paradigm - the the engineers around the N-l tools. the N-l By contrast, experience with planning and engineering tools that directly configuration address reliability reliability will quickly show any engineer that very often configuration is the key to reliability. reliability. In fact, capacity and configuration are both key factors in achieving reliability and artful engineering of power system reliability requires combining both in a synergistic manner. Traditional N-l N-l analysis tools (Figure 9.1) can analyze the functional and electrical characteristics of of configuration. configuration. However, they cannot do so on a probabilistic basis, analyzing how the likelihood that the interconnection interconnection will be there and determining how that interacts with the probabilities probabilities that the capacity of N-l analysis that need will have failed. Table 9.3 summarizes the limitations limitations ofN-l augmentation in order to meet modern modem power system reliability reliability planning needs. Such methods will will be discussed in Chapter 14. Explicit Reliability-Based Reliability-Based Engineering Methods

What is needed to assure the sufficient suffiCient requirement in power system reliability reliability engineering along with the necessary, is a method that address capacity, of the reliability of service reliability of configuration with an explicit, quantitative evaluation ofthe they provide. Ideally, Ideally, this must be a procedure that computes the reliability of of service delivered to every element of of the system, in much the same manner that a load flow computes the current flow and voltage delivered to every point in the system. It should be a procedure that can then be used by planning engineers to explore the reliability performance of of different different candidate designs, and that, in the same manner that load flows identifY identify equipment that is heavily loaded (i.e., key to electrical performance) would identifY identify equipment that is heavily loaded from a reliability reliability standpoint (i.e., key to reliable performance).

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Table 9.5 Seven Desired Traits of of the Ideal Power System Reliability Reliability Planning Method Do Not Not Have) (that N - 1 Methods Do Comments

Trait

1.I. Analysis Analysis of of probabilities

Computes actual likelihood of of all equipment in any area of the system being in service at one time. of

2. Partial Failures

Can model the de-rating of of equipment equipment in stages, rather than just zero-one outage

3. Connectivity Sensitivity Sensitivity

Can model impact of of variations in local loads, possible changes in feeder switching, etc., on expected performance.

Quantitative reliability 4. Quantitative

expected reliability of of service at points Computes actual expected throughout the network in a quantitative quantitative manner.

5. Contingency Prioritization Prioritization

assessment includes includes both likelihood Quantitative assessment likelihood and requirements in a way that permits importance against requirements prioritization of of contingency results.

6. Cost sensitive

Relates or can relate results directly to money and risk.

7. Solutions focused

Can determine or recommend recommend possible fixes based on both effectiveness and economy.

Modern Modem planning needs are best met using power system design and planning techniques that directly address reliability performance: Explicit, rather than of implicit, methods. Such techniques have been used for decades in the design of systems where reliability is of paramount importance importance - nuclear power plants for commercial and shipboard use, spacecraft design, and throughout throughout the aircraft commercial of these methods to power power systems provided a much more industry. Adaptation of operating reliability. dependable design method to achieve operating of the power system Such analysis begins with the same "base case" model of as traditional techniques did. But probabilistic analysis starts out with a true recognition that the normalcy base - a recognition the natural condition of the the system is "some equipment out" out" and that that condition will always be in a state of of flux, with equipment being repaired and put back in service, service, and other equipment out of of contingency enumeration enumeration methods, probabilistic analysis service. Like contingency can determines the the consequences consequences of every failure or combination combination of failures failures - can the system continue to operate and how close to the edge will it be during that time? But unlike traditional methods, probabilistic analysis determines if if and how every combination of of two or more simultaneous failures could interrelate to

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create problems, whether they are nearby nearby or not in the immediate immediate neighborhood, of failures is likely enough to be of and it determines if if that combination of of reliability through the configuration of concern. By tracing reliability of the system while effectively analyzes configuration analyzing expectation of of failure-to-operate, it effectively and its relationship to reliability, reliability, too. Depending on the exact method used (Chapter 14 will cover three basic Depending types), partial failures can be accommodated capacity levels, accommodated using conditional capacity partial failure states, or by recognizing sub-units within each main unit. Assumptions about loads, operating conditions, and other aspects of system operation can be modeled using probability distributions with respect to those variables. Evaluations determine and prioritize problems in the system as they will occur in the actual operation. Areas of of the system, or operating operating conditions, that are especially at risk are identified. A big plus is that the method can be fitted key identified cases - "Find the the lowest with optimization optimization engines to to solve the key cost way to make sure this potential problem won't be a real problem." problem." of a power system system can be Such methodology design of methodology for reliability-based reliability-based design created of N-I created using a highly modified form of N-l (Figure 9.1) analysis in which probability analysis is used at every stage, or by combining N-I N-l with reliabilityanalysis methods. What is best for a particular utility or situation depends on a number of of factors specific to each case. But the important point is that there are proven, widely used methods to perform this type of of work available to the power industry, and in use by selected utilities. utilities. Such methods are a key aspect aspect of of solving aging infrastructure problems: the reliability of of such system areas must be well analyzed and solutions to it well engineering. These types of of methods will be covered in Chapter 14. Table 9.6 summarizes the overall 14. recommendations recommendations on planning method improvement needed to meet modem modern reliability engineering engineering needs.

REFERENCES H. A. Daniels, Automatic Contingency-Based Analysis of Power Systems, PhD Contingency-Based Analysis of Power Dissertation, University Arlington, 1967. University of of Texas at Arlington, M. V. Engel, editor, editor, Power Distribution Planning Tutorial, IEEE Power Engineering Society, 1992 H. L. Willis, Spatial Forecasting, Marcel Dekker, New York, 1996. Spatial Electric Load Load Forecasting, H. L. Forecasting - A L. Willis and J. J. E. E. D. D. Northcote-Green, "Spatial "Spatial Electric Load Forecasting of the IEEE, February 1983. Proceedings of Tutorial Review," Proceedings

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Table 9.6 Overall Recommendations for Planning Methods Methods Comments

Method N-I contingency analysis I. 1. N-l

No reason to not use it, as it tests for a necessary criterion of of reliability and it explicitly explicitly demonstrates demonstrates for each contingency how the system will react and handle of the demand during that contingency. However, some of the better explicit reliability reliability analysis methods implicitly implicitly merge N-l N-I into their analysis, so an explicit N-I N-l analysis is no longer needed.

2. Explicit reliability analysis

of both capacity and Probabilistic analysis of contingency interconnection, configuration, including contingency expected reliability reliability of of service with computation of of the expected at all customer and intermediate points in the system. system. ofN-1 Can be based on a very modified form of N-l analysis analysis simulation) which combines (1) (I) (dynamic analytical simulation) above with this step into one comprehensive method.

3. Economic cost comparison

All reliability reliability engineering is done on the basis of of "bang for the buck."

4. Good load forecast

reliability engineering possible is wasted All the reliability wasted if the different demand level than system is designed to a different required. Good weather weather normalization and spatial allocation methods are necessary.

5. Coordinate feeder plans

Chapter I10 0 will explore engineering of of reliability reliability on the primary distribution distribution system. Effective, economical of reliability design of reliability requires coordinating subtransmission - substation level reliability reliability with primary distribution reliability, reliability, as explained there.

H. L. Willis Willis and T. D. Vismor, and R. W. Powell, "Some Aspects of of Sampling Load IEEE Transactions on Power Power Apparatus Apparatus and Systems. Curves on Distribution Systems," IEEE Systems, November 1985, p. 3221. United States Department of of Energy, Power Outages and and System Trouble (POST) (POST) Report. Report, March 2000, Washington

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10 Primary Distribution Planning and Engineering Interactions 10.1 INTRODUCTION

This chapter is in essence a continuation of of Chapter Chapter 9's 9's discussion about engineering paradigms and methods. Here, the focus is on the distribution engineering system. The power distribution system (primary feeder system) accomplishes more of of the power delivery function in most electric utility systems than any other level of the system. Power is routed into a few locations in fairly large chunks and the distribution system then routes and sub-divides that power into of very small allotments delivered to many different different locations. No other layer of the power system accomplishes so much dispersion over area or so much subof power from large to small. division of The primary distribution level also has more impact on customer power downstream of of the lowestquality than any other layer. It is both immediately downstream (substation voltage regulators level voltage regulation equipment in the system (substation of its topography, the source of the or load-tap changers), and by the nature of majority of of voltage drop that the customer sees. That topography also means that the majority of of outages that the customer sees are caused by the distribution system - there is is simply more miles of exposed line at jeopardy to weather, accident, and random failure. Thus, in most systems, the distribution system is the source of of the majority of both the voltage-related and availability-related power quality problems seen by energy consumers. consumers.

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This alone would guarantee that distribution distribution should receive a good deal of of attention anytime a utility needs to improve reliability, reliability, as for example when hard pressed by aging infrastructure issues. However, the distribution distribution system is also a resource that can be used to bolster the entire system: if combined artfully with the the sub-transmission -reliability of the substation level designs, can result in improved performance in terms of of "bang for the buck." Such planning requires, as was the case in Chapter 9, engineering methods different different from traditional traditional approaches, but methods that are proven, and widely available. distribution, the approach to its This chapter will begin with a look at distribution, planning and operation that is typically taken in the industry, and what can be accomplished by making a shift shift to a different different way of looking at and engineering the distribution distribution system, all in Section 10.2. This will introduce two key reliability at the concepts. First, using the distribution system to bolster reliability substation area through a built-in ability to transfer large loads between of marginal benefit-cost ratio balancing as an substations. Two, the use of optimization tool in power system planning. Together these lead to a much improved cost effectiveness of of the entire system. Section 10.3 will then summarize the the engineering of distribution distribution layout - how how the the spatial or geographic configuration of trunks, branches, and switching can be used to build a distribution system that has the characteristics needed. Many distribution distribution engineers are unaware of of the extent to which this aspect of of distribution distribution systems can be engineered. Section 10.4 concludes with a summary of of key points. 10.2 DISTRIBUTION PLANNING AND THE PERCEIVED ROLE OF DISTRIBUTION At its most basic, a power distribution system must be designed to deliver power over wide areas while maintaining reasonable voltage drop, and with some means of of providing redundancy (contingency switching) should anyone any one flow pathway fail. Naturally, Naturally, it is desirable to perform this function at the lowest cost providing satisfactory power quality within within standards. This compatible with providing defines the traditional traditional goal of of power distribution planning, and reflects the traditional viewpoint on the role of of power distribution system. During the early to the mid-20th century, every utility developed its own distribution planning method to satisty satisfy these needs. At each utility these evolved during subsequent decades into very tight institutionalized standards standards for "the "the way we do things." In many cases, these were nearly inflexible "template" or "cookie-cutter" approaches approaches to layout style, conductor size set, and switching zone and conductor conductor sizing. In all cases, they resulted in a distribution system that adequately fulfilled fulfilled the traditional needs of of distribution well enough to get by. The system routes power from substations to customers without violation of of voltage, loading or power factor standards. It does not cost too much. much. It is

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serviceable and expandable as needed in the future. future. Remarkably, these approaches to distribution differ differ substantially among utilities, although all those distribution systems used the same components and equipment and all fulfill much the same role. At many utilities, utilities, power distribution planning is very parochial, built upon principles developed in-house decades ago, lacking any external influence, and never comprehensively reexamined and revised with respect to modern modem needs. The reasons have a lot to do with the distribution aspect of of the utility business. Compared Compared to utility's transmission planners, distribution planners seldom have to interact with neighboring utilities utilities through intertie meetings or power pool planning groups. They are seldom exposed to the different different ideas and their particular design habits and guidelines can be challenged as that could be improved. improved. "We do it differently." As a result, nothing is quite as tightly institutionalized, nor varies quite as much, throughout the power industry, as the quality of of distribution planning. As an example, one large IOU in Florida has standards for conductor policy and feeder layout that are the exact opposite in several regards of of the practices at a large IOU in the western U.S. What is required at one utility is not permitted at the other. In fact, neither utility is correct - both paradigms are are appropriate in some cases, but not all. A more effective effective and lower cost system results when flexibility is introduced into the design: when layout, switching, and conductor sizing are engineered, rather than designed by guideline. Section 10.3, later in this chapter; will summarize several concepts related to such engineering. engineering. Frankly, engineering of of a distribution system so that it performs the basic electrical functions that were traditionally required of of it (i.e., electrical flow within standards, feasible manual switching capability for contingencies) is rather straightforward. At many utilities, utilities, this was done for decades with a standardized layout rule, a set of of tailored nomographs and tables and some rough calculations (slide rules at best), all guided by a series of rote-memorized rules of thumb. When digital computers became available, load flow computations and spreadsheet-level tools were adapted by each utility to its particular distribution paradigm. The basic concepts underlying each utility's method -- how things are done and the fact that the engineering is largely based on a set in place. set of inflexible rules - remained in Both because adequate distribution planning is so straightforward to do, and because it is done at many utilities with the fairly straightforward templateguideline-type of approach, one often often hears the terms "it isn't rocket science" applied to distribution planning. This belief belief that distribution is easy to plan, and effort is wasted in its engineering, is that significant and high-expertise effort exacerbated exacerbated by the facts that distribution is of relatively low voltage compared to other parts of the power system, that the equipment involved is small and inexpensive (compared to other levels,) and, that the system is normally laid out

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in radial form (which makes power flow easy to calculate). All of of this tends to make distribution seem simplistic, and in fact it is, if viewed only from the traditional perspective, that the task is just to "get "get it so it works." Distribution Can Be Asked To Do A Lot More

However, that traditional interpretation of job is of the distribution system's job obsolete and incomplete with respect to modem modern societal needs and technical capabilities. When reliability of of supply is a major performance performance metric, and minimized, not just kept within when cost must be minimized, within traditional bounds, distribution planning becomes very challenging. challenging. The important point to realize, however, is that the effort effort required meeting this challenge more than pays for itself: the gap between the performance of of really good distribution, distribution, and merely "adequate" ones, is immense. This gap manifests itself in two ways: •

Economics: Economics: Advanced engineering and and flexibility of approach can yield considerable reduction in cost.



Reliability: The The potential potential of the the primary system to maximally contribute to improved reliability is partially untapped in the vast majority of of cases.

A key factor in both is that the distribution system is both engineered well (optimized) and its design is coordinated carefully carefully with that of of the subtraditionally done. transmission and substation levels in ways not traditionally Table 10.1 10.1 shows the results generated by this approach at six utilities with of all which the authors have recently worked. These utilities are representative of the utilities utilities the the authors have worked with over the the past decade - they are are an average set, not one picked to show outstandingly good results. Together they demonstrate both the margin of of improvement that can be expected by updating and modernizing primary distribution distribution planning and design paradigms, the variation in improvement and type of of improvement that are seen among different different utilities. Table 10.1 lists four statistics for each system. The first, "Electrical "Electrical - $," is the reduction in overall (lifetime) cost of of distribution that could be wrought with respect to the traditional primary distribution distribution paradigm of of moving power. This is the saving in new capital additions that results from improving how the distribution system is to do is designed to do its its traditional job - moving power. The second statistic, "Existing "Existing - $" shows how much the useful utilization of of an existing existing distribution system can be improved with respect to that traditional paradigm. Existing systems encompass both the good and bad points of of their past engineering and design, and those systems cannot be thrown away and redesigned based on new and improved rules. However, as shown, some

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Table 10.1 Improvements in Distribution System Cost and Performance Derived from Table from Revision of of Traditional Design Guidelines and Engineering Methods Case

Utility System Type

Electrical $ Existing $

11

Urban UG, Atlantic Atlantic coast

2 3 4 5 6

Rural, small towns, central US

8%

Metropolitan, Midwest US

6%

IOU, central US Entire system, IOU,

2%

Rural, small towns, southern US

12%

2% 0% 3% 3% 11%

Entire system, N.E. US

22% 10%

Averages Averages

12%

Reliability $ System Reli. 79%

3.4:1 3.4: 1

25%

.8:1

40%

1.8: 1.8:11

36%

1.5:1

31%

1.6:1

16% 16%

33%

.92:1

6%

41%

1.7:1

improvement can be wrought in the MW /$ capability of of these systems. MW/$ useful (if MV A However, improvement is only useful where useful (if one improves a 5.0 MVA feeder so it can carry 5.4 MVA, the increase is useless unless it is in an area where one needs a .4 MVA increase in capability). The values shown in Table 10.1 reflect both what is possible and what was found useful in each system. The third statistic, "Reliability - $," represents the reduction in the cost of improving attained by revising design guidelines and improving reliability reliability that was attained applying the most effective effective reliability-based planning and engineering engineering methods to these systems. These improvements while rather dramatic, are typical. As stated earlier, distribution systems are simply not designed designed from a reliability standpoint. When this is done and the engineering engineering is optimized, the results are a very considerable improvement. The final statistic "System "System Rel.(Reliability)" represents the margin in "bang for the buck" that the revised distribution reliability improvement made over the existing cost of improving reliability that was in effect effect before the revision. This statistic goes to the heart of of the use of distribution as a resource in aging infrastructure areas, and of of using all of the power of the authors' overall theme of system chain optimally to obtain the greatest greatest "bang for the buck." In four of of the reliability improvement improvement was between 20% and 40% less six cases listed, reliability expensive to buy at the primary level than at other levels of of the system. In these cases, spending on the distribution system could deliver reliability improvement for less cost than spending on other levels of of the system. In two other cases, this was not the case, and the value shown is negative. Of Of note here is that the utilities were unaware of of this entire issue, because the of all three levels were not traditional tools they were using for the design of of directly engineering reliability or of even measuring such things as capable of

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314 reliability improvement per dollar. Thus, in all cases, 9% (11.92 (1/.92 - see see final column) and and 70% 70% were possible based engineering methods and using them well at the based for coordination of of design among the distribution distribution substation levels.

Chapter 10 improvements improvements between between by adopting adopting reliabilitydistribution system and and sub-transmissionsub-transmission-

A Quantum Difference Difference in "Bang "Bang for the Buck" Buck" distribution system system guidelines guidelines and Table 10.1 made it clear than revision of distribution adoption of adoption of reliability-based engineering engineering methods often (actually in all cases the authors know) provides a good The increases increases in cost good improvement. effectiveness effectiveness of of 10% and 6% versus the traditional distribution distribution function are noticeable and quite valuable. However, it is the improvement from the "modem perspective" - that which views distribution's role as "modern perspective" as one one of both performing the electrical duties and fitting into the optimum reliability vs. cost structure structure of the the entire system - where the the improvement represents represents a quantum leap. By looking at the distribution system as a reliability resource, and optimizing its use for that purpose, an average 40% increase in cost effectiveness reliability improvement is obtained at the distribution level. By effectiveness of of reliability coordination coordination with the planning and design of of other levels of of the system, a 70% increase in overall effectiveness of of money spent on reliability improvement is achieved. The authors are aware than many readers, readers, particularly some with long experience as distribution planners at power power delivery utilities, will dispute that the improvements shown are real (they were), or will argue that that their system is different won't work here" (it will). different (not likely) and that "it won't will). The six cases cases shown are all real utilities utilities implemented long enough in the past that time has proven the expected expected savings and performance increases to be valid. The 6% and 10% savings against normal needs come about because modem modern techniques can find better ways to reduce costs than the formalistic methods of of the past. But the quantum gains in reliability reliability and reliability reliability improvement per dollar come from the fact that because of of its dispersed nature, the feeder system weaknesses in reliability reliability can often be reinforced at reasonable cost to cover weaknesses (contingencies) (contingencies) at the substation substation level. The concept concept is easy to understand, if not to engineer engineer (at least with traditional tools). Suppose Suppose that for whatever reason, reliability reliability at one substation is a particularly degraded degraded level of of expected reliability. Perhaps the utility has no choice but to accept very high equipment utilization utilization at the substation and there is a less than ideal configuration of of buswork and switchgear there to provide contingency flexibility. flexibility. The feeder system system in this substation substation area could could be reinforced to provide "more "more than the normal amount of of primary feeder level reliability strength" strength" to make up for this deficiency. deficiency. Specifically, since this

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Primary Distribution Planning and Engineering Interactions

315

substation will be out of service more than usual, the feeder system can be designed to transfer its loads to other neighboring substations, maintaining service during those contingencies. This is really what is necessary to provide high-utilization systems, particular in the aging areas where good service in high-utilization substations are congested and highly flexible switching and buswork is not an option. Good Distribution Distribution Planning Is Rocket Science Science

Despite the fact that what might be called "commodity" design can create a power distribution distribution system that will work "well enough," the power distribution difficult of of all layers in the power system to plan and system is by far the most difficult engineer to a truly high standard. Meeting this challenge is difficult, because of great distribution systems are like piranha. A single piranha is small, and not of of piranha become something entirely concern, but in aggregate, a group of different. of low Like the piranha, almost every unit in a distribution system is small, of voltage, commodity design, and low price. But in aggregate a distribution very complicated. This system becomes large, expensive, and most importantly, very of components (perhaps millions) millions) and the their is due to both the sheer number of interconnectedness or interaction with one another (particularly if viewed from reliability perspective). A distribution the reliability distribution system presents a tremendous combinatorial decision-making -— how to select equipment, route challenge in combinatorial lines, site key equipment and switches, taper conductor, arrange normal nonnal and contingency flow patterns, and makes a myriad of other decisions needed. The combinatorial aspect is tremendous, resulting from the fact that not only are combinatorial there dozens or even hundreds of of individual decisions to make in even a small distribution layout problem, but also because these individual decisions all interact with one another. No decision can be made in isolation: they all influence one another. of It is possible to sidestep this combinatorial challenge by using a set of standardized layout rules, templates on sizing and design, and inflexible guidelines on equipment and engineering. This was how utilities utilities approached distribution in the 1930s. By sacrificings the gains in cost and perfonnance performance that might be obtainable, in exchange for a tremendous simplification simplification in the process of finding a workable plan for every situation. This template approach does of assure that minimum electric requirements are met, and that cost, while perhaps not optimum, is not unduly high (perhaps no more than 10% above the minimum possible). However, maximizing benefit, and particularly, tailoring distribution in each area of of the system to fit the specific needs and the characteristics characteristics of of other levels of the system there, means facing up to that combinatorial challenge. The of possibilities within all that flexibility have to be exploited. That means dealing

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Chapter 10

316

with all those interrelated interrelated decisions and obtaining plans that are close to effective manner possible, is optimality. Distribution planning, done to the most effective rocket science. Section 10.3 10.3 will summarize design and planning methods that accomplish these goals in a practical sense - they deliver results in the real world. However, they require new ideas and slightly slightly more work than traditional distribution planning: methods, which brings up a final point about modern modem distribution Feeder System Strength

of the The "strength" of a feeder system will be defined here as the percent of substation load that can be transferred to neighboring substations during of a distribution distribution system that can be contingencies. This is a characteristic of of anywhere from zero to one hundred percent. The designed to have a value of of the scale and everywhere in authors have worked with systems at both ends of between. There is no single, recommended target for the feeder system strength. It depends on the voltages, capacities, demands, configurations and constraints on level, the capabilities of the the sub-transmission - substation level, the capabilities the type of of distribution system being built, and the need for reliable service as interpreted by the consumers and the utility alike. Figure 10.1 shows the reliability versus 30

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10 20 30 40 50 Expected Annual Contribution Contribution to SAlOl· SAIDI - min.

60

layers of Figure 10.2 Top, cost vs. SAIDI SAIDI curves for the different different layers of a power system. candidate design, provide Dots show the status of of each layer in a candidate design, which which in aggregate provide 119 minutes of of SAID SAIDII annually annually at an annualized cost of of $172. Bottom, by adjusting the feeder system design to "buy" "buy" ten minutes of of SAIDI SAIDI improvement for $5.00, and saving $5.00 by cutting at the substation substation level, a net improvement improvement of of five minutes SAIDI SAIDI is obtained at no cost: SAIDI is now 114 minutes and cost is still $172.

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Primary Distribution Planning and Engineering Interactions

319

demand (the sums of of the reliabilities and costs of of all the dots, respectively, equals these two values). The important items for improving reliability are not of the dot) of the actual value (i.e. position of of reliability vs. cost for any of these points. Instead, it is the slope of of the cost vs. reliability curve at those points. For example, the primary feeder level design is at 57 minutes and $24lkW $24/kW annualized cost. However, the slope at that point indicates that spending an additional five dollars will improve reliability by ten minutes (moving the dot along the curve to the left by ten minutes raises cost by five dollars). By contrast, buying ten minutes at the substation level (see curve and dot for that level) would cost $32.00. Clearly, the way to improve reliability at a bargain price is to buy improvements in the feeder system. system. But beyond this, in this candidate design, one can begin improving reliability without spending any additional budget by "trading" reliability and cost between of the feeder and substation levels. This can be done by "buying" ten minutes of five dollars worth reliability at the feeder level level for five dollars, and "selling "selling off' off five of reliability at the substation level, which because because of of reliability of the slope of of that curve, means giving up only five minutes of of SAIDI. Overall performance is improved by five minutes at no change in overall cost.

Service circuits

150

Service transf. Subtransmission Substations

100

Primary feeders

o

O

50

o~---------------------------------------60 40 10 20 30 50 o SAIDI - min. min. Expected Annual Contribution to SAlOl· Figure 10.3 The candidate design is adjusted until all the levels have the same marginal reliability (dotted cost (slope) of of reliability (dotted lines). SAIDI for this design is 91 91 minutes at the same overall cost of$I72/kW. of $172/kW.

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320

Chapter 10

Thus modified (bottom plot), the slopes of of the feeder and substation levels are still not equal, so this "trick" can be applied again, buying 13 13 minutes at the feeder level in exchange exchange for eight minutes at the substation. This brings SAID! SAIDI down to 110 minutes at no increase in cost - annualized cost is still $172. Far curves can be adjusted in this way, with the beyond this, the points in all the curves result shown in Figure 10.3. The final result is a SAIDI of of 91 91 minutes at the same $172IkW $172/kW annualized cost. The example shown is a slightly simplified example based on case 5 in Table 10.1. In the real world, the curves for each level have discontinuities discontinuities and small but frequent discrete jumps, and there is some interaction and interdependence among the curves. But the concept shown is a valid and workable approach, and it leads to viable, noticeable improvements in reliability, reliability, at no net increase in cost. In this case, to accomplish these improvements, more was spent on the distribution system and less on substation configuration and redundancy: different style (see large trunk vs. multidistribution was both designed to a different branch in section 10.3) and its strength was augmented in selected areas. Paradigm Changing the Distribution Paradigm Chapter I1 (pages 28-30) discussed a number of of "cultural "cultural barriers" that often stand in the way of power delivery system performance using "non of improving power traditional ways. In the authors' experience, the technical methodology required to successfully implement the distribution distribution system performance improvements utilities than the cultural discussed above are far less challenging to most utilities changes required to fit it into their organization. Considerable commitment changes from executive management, and steady effort effort to accomplish the change, are required.

EFFECTIVENESS 10.3 FLEXIBILITY AND EFFECTIVENESS IN FEEDER LEVEL LEVEL PLANNING Generally, N-l N-I criteria and planning methods were traditionally traditionally applied to to the the sub-transmission - substation portion of the the power delivery only to system, everything from the low side (feeder) breakers upward toward the wholesale grid (Figure 10.4). It was and still is uncommon to see that method applied to the distribution distribution feeder system, although concepts concepts allied with N-I N-l criteria often are. The primary reasons for this difference difference in of the substation feeder breaker are: methods on each side of Tradition - in utilities of the the 1930s through in vertically integrated electric utilities 1990s, the Transmission Engineering Department most typically of the system above the feeder breaker, the Distribution Distribution engineered all of Engineering Department engineered the feeder system and everything downstream of of it. At most utilities they evolved different different methods.

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321

Transmission

Sub-transmission

N - X criteria and methods traditionally applied

Substatton Feeder switching studies traditionally applied Service/Secondary A

Customer 10.4 N-I N-l criterion (Chapter 9) is applied to the power system at the Figure 10.4 transmission, sub-transmission, sub-transmission, and substation level analysis. Generally, feeder switching studies are done to assure "reliability" at the feeder level.

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322

Chapter 10

Applicabilitynot be applied to Applicability - The N-X study method (Figure 9.1) can can not distribution feeder systems without significant modification of of the traditional "modified load flow" approach. Distribution level application would involve representation of of manual and/or automated switching operations, in precedence, which requires a much more involved algorithm, both in terms of of internal complexity and user effort. effort. Different the distribution feeder level, reliability Different paradigm - Generally, at the level, reliability is addressed through switching redundancy design, as will be discussed below.

Feeder Contingency Switching

Traditionally, reliability-assurance methods for feeder level engineering varied greatly throughout the power industry, there being no standard standard or nonn norm to which most utilities utilities adhered. However, reliability engineering engineering of feeders recognized certain characteristics at the feeder level: •

Feeder circuits are are radial, as as such, an an equipment failure leads leads to to an interruption of of flow of of power to customers.



Switching can can restore service in in advance of repair. Switches to isolate failed sections and to switch feed of of power to alternate routes are provided at points throughout the feeder system, so that line crews can restore service prior to making repairs. Figure 10.5 illustrates this basic concept.

Multiple Switches Divide Each Feeder into "Switch Zones"

Although practice varied greatly among electric utilities utilities both within the U.S. and internationally, the traditional traditional concept for "building reliability" into a feeder system design was to place several switches at points on each feeder to segment it, with portions transferred to neighboring feeders. Figure 10.6 illustrates this point. The tie switch near the feeder pennits permits the feeder to be fed from an adjacent feeder leaving the same substation. (If the design of of the substationsubstationfeeder system is sound, the adjacent feeder will emanate from a low-side bus of different different than this feeder's, pennitting permitting service to be restored with this type of switching, even if the outaged feeder's low-side bus is out of of service). service). Alternatively, a second feed option is usually available on most feeders. The pennits it to be supported from a feeder from tie switch at the end of the feeder permits another substation, as was shown in Figure 10.5.

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Primary Distribution Planning and Engineering Interactions

323

t TT

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Figure 10.5 Example of of feeder switching. Top, feeder from substation 1I and feeder Figure from substation 2 are both in service. In the middle, a line failure at the location shown interrupts service to all customers on line now shown as dotted (the entire feeder). Bottom, a normally normally closed feeder switch is opened to isolate the failed section, and a normally open feeder tie switch between the two feeder end points is closed, restoring service to a majority of of the customers on the outaged feeder. Only those portions shown as dotted lines are now without service (they must await repair of of the damaged line). After repairs are made, the switching sequence is reserved to go back to normal normal configuration.

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324

Chapter 10

n.o.

Figure Figure 10.6 Top, a single feeder in a feeder system, in this case one of of four identical (symmetrical) (symmetrical) feeders from a substation. It has normally closed closed (N.c.) (N.C.) and normally other feeders. Bottom, these four switches open, (N.O.) (N.O.) switches switches which tie it to other switches segment each is isolated (if it into "switch zones" in which each (if a failed line section section is in that zone) or during a contingency, so service is maintained maintained despite the transferred to adjacent feeders during failure in one zone.

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Primary Distribution Planning and Engineering Interactions

325

Voltage, Loading Criteria, and Line Upgrades for Feeder Feeder Contingencies Upgrades During a contingency, when loads have been transferred, the feeder picking up additional load will experience higher than normal loading levels and voltage drops on the re-switched portion of of its system. Referring to Figure 10.5, bottom, in that switched contingency configuration, the feeder from substation 2 is supporting roughly about 180% of of its normal load (all of of its customer demands and about 80% of offeeder feeder 1's). 's). Current Currentflow flow on on its itstrunk trunk isisthus thus 80% 80%higher higher than than under normal conditions, and voltage drop correspondingly correspondingly 80% higher. In of feeder 1 that has been picked up addition, the power flow to the portion of during the the contingency is over a far far longer route than under normal conditions -voltage drop will be even more than 180% of of normal: it might reach over two times the normal voltage drop. Figure 10.7 illustrates this this..

/Range 8 B limit limit • • /rRange

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Figure 10.7 Two large-trunk feeders tied together for contingency contingency support. The feeder experienced a failure of equipment at the substation (shown by an X). on the right has experienced Switch B has been opened, switch at A has been closed, so that the feeder on the left of feeder loads. The feeder on the left is now serving twice its normal supports both sets of load. Even though its conductor conductor has some margin over peak load, the 200% load pushes it far beyond acceptable acceptable loading limits. Dotted lines show the points where voltage drop reaches range B limit using normally sized conductor. Voltages are symmetrical about the trunk, but the profiles are shown only for the northern side. This means voltages beyond the dotted line are unacceptably low, even when compared compared to the already relaxed unacceptable loading levels and standards applied during contingencies. Thus, to avoid unacceptable voltage drops during contingencies, the conductor size on both feeders must be increased to a larger wire size, far beyond that needed for normal service.

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326

Chapter 10

Again, although standards and practices vary greatly throughout the power industry, often often utilities utilities will reinforce the trunk of of each feeder (use larger conductor conductor or cable than needed to serve the peak demand), so that capacity and voltage drop capability are available available for contingencies. This reinforced capacity is not needed during normal operations; it exists purely to augment contingency justitied on the basis of capability. Its cost is justified of reliability improvement Generally, utilities also apply different different standards for what is acceptable loading and voltage drop during during contingencies, than they do for what is acceptable under normal circumstances. While practices vary, many utilities use ANSI C84.1-1989 range A-voltages as design criteria for normal conditions on their system, and range B for contingencies scenarios. Range A specifies a 7.5% maximum voltage drop on the primary feeder system (9 volts on a 120 volt scale, maximum) maximum) during normal conditions (no failures). failures). Range B, which applies during during contingencies, contingencies, permits voltage drops of of up to 13 13 volts on a 120 volt scale (10.8% voltage drop drop).).11 Similarly, loading criteria during emergencies emergencies typically typically permit excursions past the limitations limitations set on expected loading during normal service. A particular conductor might be rated at a maximum of of 500 amps, a substation transformer at is operating as MV A for 24 MVA for normal service - whenever everything is as planned. Under emergency or contingency operation, however, the conductor might be permitted a loading of of 666 amps (133%) for six hours, and the transformer transformer up to 30 MVA (125%) for four hours. utilities follow hours. While While not all utilities follow these specific standards, most follow something similar. The establishment and application of of emergency loading and voltage standards is a recommended practice, so that while the same rigid requirements of of nonnal normal service need not be met during contingencies, some minimally-acceptable minimally-acceptable standards do have to be met, to provide a uniform uniform target for contingency planning planning and operations. Traditional Engineering and Planning Feeder Systems Systems for Reliability

of feeder system reliability can be assured engineering each Reasonable levels of feeder into an appropriate number and location of of switchable zones, and arranging the line pathway of of neighboring feeders so that they have the capacity capacity to support support these switchable zone loads [Willis, 1998]. During the latter fourth of of the 20 thth century, practices at the feeder system level varied tremendously amount traditional traditional regulated, vertically integrated electric utilities. utilities. The quality quality of of engineering and planning, planning, and the amount of of scrutiny and detail detail paid to reliability reliability design at the feeder level, level, varied greatly industry. Some utilities had tough standards and rigorous engineering over the industry.

1 I

See the IEEE Red Book -for Electric Power Distribution for — Recommended Recommended Practice for for Industrial Plants. Industrial Plants.

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Primary Distribution Planning and Engineering Interactions

327

methods. Most, however, applied simple formula methods based on topology and standardized layouts.2 Weaknesses in Weaknesses in Traditional Systems Systems

substation level discussed in section As was the case at the sub-transmission - substation 9.2, as budget pressures increased throughout the 1980s and 1990s, utilities responding by cutting back on reinforcement of of their feeder system as their loads grew, and accepted higher utilization ratios (peak load/capability ratio) as a consequence. This had an impact at the feeder level that is qualitatively similar to to that at at the the sub-transmission sub-transmission - substation level discussed earlier. Higher utilization ratios eroded contingency margin. Situations where contingency currents were too high, and contingency voltage drops too low, became not uncommon in many utilities, limiting their ability to restore service quickly during storms and when equipment failed, and generally leading to degraded customer availability. Furthermore, at many utilities where budgets were cut back significantly, planners were forced to use the contingency switching capability of the existing system to accommodate load growth. When the customer customer demand in one feeder area grew to where it exceeded the feeder's capability, a zone would be transferred to neighboring feeders. At several utilities utilities (e.g., Commonwealth Edison of of Chicago) widespread application of of this stopgap approach during the 1990s "used up" much of the contingency withstand capability of of the feeder system. Optimizing Engineering Engineering and Planning Planning of Feeder Feeder Systems for Reliability

As was observed earlier, adequate and even superior superior customer service level reliability can be assured by properly engineering engineering the switching and capacity margin of of the feeder system. This level of reliability can be accomplished by engineering each feeder into an appropriate number and location of of switchable zones. A key factor of of success is the artful arrangement of of the circuit pathways for each feeder and its neighbors so that all have the capacity to support switchable zone loads, and so that there are a sufficient sufficient number of strategically placed intersections at which to put switches. This type of engineering can be involved and can require specialized techniques and approaches to work best, but there are proven methods in well- documented sources. See the Power

2 2

For example, switches were not located so they would segment the feeder into into zones purely on topology, at branches designed for improved improved reliability, but located based purely points and intermediate intermediate locations locations along long trunks.

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328

Chapter 10

Newer Multibranch style

Traditional Big trunk layout

o

=

=

=

SAIDI = = 1.41 SAIFI = 1.17 SAlOl Initial Cost = $903,000

SAIFI = 1.38 SAIDI SAlOl = 1.77 Initial Cost = $985,000 normally normally open switches 0 O

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Figure 10.8 Left, the traditional traditional large trunk feeder design, a simple simple to engineer and operate feeder layout based on 19305 1930s engineering technologies. It has tie points to feeders at both ends of of the trunk (Figure (Figure 10.7). Right, Right, a multi-branch feeder serving the switches and switching switching zones, with same area, designed to the same standards, has more switches of it, and at its end points. It is more ties to similar multi-branch multi-branch feeders on both sides of difficult to engineer. difficult engineer. But it but costs less and delivers delivers better reliability. The point is that switching and layout can be engineered maximum reliability per dollar. engineered to deliver maximum

Book (Willis, Distribution Planning Reference Reference Book (Willis, 1997), Chapters 8 and 9, for a of switch zone engineering methods and design trade-offs. detailed discussion of As an example of of the difference difference such methods can make, Figure 10.8 shows a feeder layout called a short-contingency path, multi-branch feeder. This feeder has a more "dendrillic structure" (repeated hierarchical branching into more and smaller smaller flow paths) as compared to the large trunk feeders shown in Figures 10.5 and 10.6. Large trunk feeders are the most traditional traditional types of of feeder design, having only one path that is used in contingency switching (their trunk). Large trunk designs date from the 1930s and are used, mainly due to tradition, as the layout concept for feeder engineering at about half of of all utilities utilities in the U.S. By contrast, the multi branch feeder shown has a more complicated layout consisting of of branches and sub-branches. These segment it into more and smaller zones. Basically, the feeder is broken into smaller "chunks" for contingency operation, and those chunks are transferred among several neighboring feeders during a contingency. contingency. This means:

A smaller of the feeder feeder customer customer base will will be smaller portion of unrestorable unrestorable due to the failure. The switched zone containing equipment can never be transferred. Service in that one failed equipment

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zone can be restored only by repair. Smaller zones mean a smaller portion of of the customer base falls into this category during every outage. Consequently, a higher proportion of the customers can be restored through re-switching, cutting average interruption time. Less contingency margin is needed. Loading levels and voltage drops during contingencies are far lower than with large trunk designs. Such a system is more challenging to design, although with modern modem electronic feeder CAD systems, this is quite within the grasp of of any reasonably trained distribution-planning engineer. Short pathways pathways mean lower voltage drop. Although not obvious from visual inspection, the increase in MW-mile MW-mile of of flow during contingencies contingencies in the multi-branch shown is much less than in the large trunk designs. This means less money contingency capacity must be spent on conductor upgrades for contingency and voltage drop capability (Figure 10.7).

High engineering and operating complexity. A distribution system composed of of this type of feeder does involve slightly more work to design, and to operate well during contingencies. contingencies. However, the widespread use of of CAD systems for feeder planning and CAM systems for distribution operations makes such capabilities commonplace. The net impact of of the above is that the multi-branch feeder has a 12% better SAIDI and 8% lower capital cost to serve the same load, while requiring roughly SAID! 10% more engineering effort effort and the same overall O&M cost. The point of of this discussion is not to promote the use of of multi-branch of layout types besides large-trunk feeders (there are other types of large-trunk and multibranch, and all have advantages advantages and disadvantages that need to be carefully carefully weighed in each situation). Rather, what is important here is that feeder layout, switching, and reliability can be engineered well, using proven methods. How this is done will be summarized in Chapters l3 13 and 14. StrategiC Analysis and Optimization Strategic Planning --Analysis of the Utility Feeder System's System's "Strength"

Feeder systems can be engineered to provide only contingency support capability for feeder-level failures or to provide support through the feeder system for for substation outages as as well. Providing Providing support for for feeder outages -designing the feeder system so that it has switching and contingency contingency capability

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to provide backup during failures on the feeder system, is certainly a best practice, and practically mandatory for, urban and suburban systems. 3 Layout, conductor size, and switching can be engineered so that all, or only a portion, of of each feeder's load can be transferred to neighboring neighboring feeders. The primary means of of supporting a feeder's outage is to transfer its switching switching zones to adjacent feeders out of of the same substation. This keeps the substation load as close as possible to actual, and is generally easier to accomplish in practice (line (line crews have to drive shorter distances to reach the various switches involved). It is also often considered a more prudent policy to transfer loads of one substation, rather than between feeders served by only between feeders of different different substations. 4 Designing a Feeder System to Partly or Fully Support Substation Outages

If If a particular feeder can be transferred so that it is completely served through a tie to a feeder emanating from a neighboring substation, then its electric consumers can remain in service during the failure of of its substation (or the portion serving it). The ability to transfer the entire feeder load requires great strength among neighboring feeders in terms of of feeder trunk capacity and voltage (factors such as discussed in Figures 10.7 - 10.8). A general capability to do this throughout a system - a feeder system designed so so all all feeders for for any can be transferred among its its neighbors - results in what is termed one substation can a "strong" feeder system."

3 3

Given that most feeder systems are radial, radial, there is no other way to assure quick termination of of customer interruptions interruptions caused by feeder failures. In the design of of rural distribution systems, there generally is no switching capability, due to the distances and neighboring scarcity of of the system. But in suburban suburban and urban systems where there are neighboring feeders in all areas, the design of of the system to switch around feeder-level feeder-level outages is a given in almost all utility systems. fiven desire, when switching configuration The issue here is mostly a desire, switching back to the original original configuration after the outage is repaired, of of avoiding avoiding a short-term interruption interruption of service to any fore-break" switching. customers. To do so, the utility has to use "hot" "hot" or "make-be "make-before-break" switching. The "to" permanent feed feeder is closed before the "from" switch "to" tie switch to the permanent connecting it to the temporary temporary contingency contingency feeder is opened). For a moment during during this process the transferable transferable section has two feeds. This avoids a short interruption to the customer, which which occurs if the "from" "from" switch switch is opened prior to closing the switch to the other source. Hot switching switching between feeders feeders served by the same substation is generally "safe" in the sense that it will cause no loop flows flows or overloads. But hot switching on feeders of different substations can create high loop flows, if phase angle differences differences of different between the substations, caused by circuit circuit flows flows on the transmission transmission system is large. Some utilities have a firm policy pol icy of of not doing such switching switching between substations, and as a result, result, prefer to do only only switching switching only between feeders feeders served by the same substation.

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Clearly, to pennit permit this to work well, in addition to a strong feeder system, the substations substations themselves must also have contingency contingency withstand capability to However this usually is not a design accept the additional transferred loads. However its increased utilization utilization problem. In fact, use of of a strong feeder system penn permits ratios (peak load/capability ratio) at the substation level, level, i.e., lower contingency If a substation transfonner margin in substation designs. If transformer fails, fails, the remaining transfonner(s) at the station do transfonner's load - it transformer(s) do not have to pick up that transformer's can be distributed over many transformers of the feeders to transfonners by transferring some of neighboring substations. substations. Often, a utility will design its feeder system to support support a limited amount of of feeder load transfers to neighboring substations. For example, suppose that the outennost outermost 1/3 1/3 of of load on every feeder can be transferred to neighboring feeders. This is not an undue amount ofload of load (1/3 that of of transferring the full feeders) and more importantly, is the portion of of load closest to the neighboring feeders, meaning flow paths and voltage drops are lower, so that it is not typically difficult to arrange. difficult With this feeder system strength, the loss of of one of of two identical transfonners transformers at a substation can be supported, even if if they are both loaded to 100% at peak, with an overload of of only 33%. During the contingency, load of a transformer's transfonner's capacity is transferred to neighboring amounting to 66% of substations (the outennost outermost 1/3 1/3 portion of of feeders served by both transfonners), transformers), leaving the remaining 133% to be served by the one unit in place. Overloading is equivalent to what occurs without feeder transfers, transfers, if the transfonners transformers were loaded to only 66%. The ability to transfer 33% of of feeder loads results in an ability to increase transfonner transformer loading by 50% (from 55% to 100% or rating) with no increase in substation contingency stress levels. Optimizing the amount of of strength in a feeder system can be accomplished of feeder strength against the marginal savings in by balancing the marginal cost of transfonner transformer capacity. Again, as throughout this book, the keys to success in gaining reliability/dollar are: •

Systems approach -- in in this case the the feeder feeder and and substation levels need to be considered simultaneously, trading strength at one level against the other, in order to achieve reliability targets at minimum cost.



Marginal cost optimization -- as as described elsewhere, the the planners planners "buy" "buy" and "sell" reliability between levels until there is no bargain either level. at eithcr

of this design approach approach results in areas of of the In any real system, application of stronger and weaker feeders, and weaker weaker and stronger substations system with stronger

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Chapter 10

332

rr

QreMIe

Figure Figure 10.9 Feeder configuration evolution. evolution. By selectively reinforcing segments and changing configuration, an existing large-trunk feeder (left) can be modified, or through multi-branch feeder with greater greater inter-substation tie gradual changes, evolved, into a multi-branch capability (right). (right). Engineering Engineering such changes so that they both work well, and fit fit within within constraints of of route and duct size, etc., and fit budget and work management schedules, requires a modern modern feeder system CAD software package package with optimization optimization generally requires capabilities. But, this is well within the capability capability of of several existing commercial, feeder design software systems.

respectively. These differences are due to constraints and factors unique to locations throughout the system. At substations where there is a limitation in capacity, a high utilization factor already, and very high marginal cost for any additions, reinforcement of reliability by use of a strong feeder system is generally the lowest cost option. Similarly there are areas where the reliability level less expensively than at the feeder level. can be bought at the substation level like this this overall, overall, delivers delivers the But the fact is that the system if designed like performance required at minimum minimum cost. cost. Increasing Feeder Strength Strength to Augment Augment Aging Infrastructures Infrastructures

expensive, Generally, in aging infrastructure situations it is impossible, or very expensive, the substations -- sites are are small small relative relative to to need and and tightly tightly packed packed to augment the with equipment. Reinforcement of the feeder system to add strength is a good as it can usually be achieved within within means of improving reliability overall, as existing constraints constraints and at lower cost. Such design, called configuration configuration

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333

evolution, is not practiced by most utilities but is feasible and long proven in numerous cases (Figure lO.9). 10.9). of configuration evolution can be found in the Power Distribution Details of Planning Reference Reference Book. The important point here is that the reliability of a Planning system, aged infrastructure or not, can be managed through artful use of modem of modern reliability-engineering methods. 10.4 10.4 CONCLUSION CONCLUSION

Distribution systems often provide fertile ground for cost-effective improvement of reliability. This is not only due to the fact that many power of power system reliability. quality problems start at the distribution level and are therefore most effectively effectively solved there. It is also because the distribution level can be used to provide load transfer capability between substations, thus reinforcing weaknesses in the overall customer service reliability chain due to weaknesses at the subtransmission and and substation levels. A distribution system's strength - its its ability to transfer load between substations substations - can can be tailored as as needed at locations throughout throughout the power system. In aging infrastructure areas, reliability-based augmentation augmentation of of the distribution system is a particularly attractive option for improvement of of overall customer service quality. Basically, the cost of of "buying" reliability often far less than at the subimprovements at the primary feeder level is often transmission and substation levels, which are far more constrained. The distribution has has a small granularity - it be upgraded in and it can can be in stages - and designed to bolster sub-transmission/substation essentially evolved into a system designed level weaknesses. This is not to say that distribution distribution can provide all, or even most, of of the "cure" needed in aging infrastructure areas, but it is one of the most effective effective among the many options which a utility can assemble into a viable overall plan. Explicit Distribution Reliability Methods

Distribution planning and methods traditionally used at most utilities applied standardized concepts, often often not completely articulated, but instead institutionalized as tacit knowledge or culture, for how the system should be laid out, tables used, and guideline-driven guideline-driven design methods to simplify simplify effort effort and engineering. While adequate to meet the traditional expectations for of the distribution system, these did not address reliability directly performance of nor get the maximum possible from the distribution system in terms of of reliability interaction with other levels, or economy. For these reasons, modem modern planning needs are best met using power system design and planning techniques that directly address reliability performance.

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334

Chapter 10

The most important points are:

1.

Systems Approach Approach - planning of the distribution system must be Systems completely coordinated with the sub-transmission and substation levels. The goal is not to design an optimal distribution distribution level, or Any one portion substation level, but to design an optimum system. Anyone of that whole might be decidedly "non-optimum" until its context of within the entire system is taken into account.

2.

vs. performance performance among multiple levels of Balancing of of cost vs. of the system using adjustment of of design based on achieving equivalent reliability. This results in near-optimum use of marginal cost of of reliability. of limited funds to "buy" reliability improvements. "buy" reliability

3.

of Engineering of of configuration configuration and switching - a wide variety of possibilities in the overall overall layout of of a feeder exist and should be reviewed in order to pick the best approach for the needs in each area. Very often often standards at a utility will be so tightly of neither other options institutionalized that engineers are not aware of nor the advantages they could obtain with flexibility of of configuration and layout.

4.

Reliability-based engineering - explicit rather than implicit methods Reliability-based for reliability engineering of of the distribution system. Applications of of these methods to power systems provided a much more dependable design method to achieve operating reliability. reliability.

concepts to aging Dependable, practical, methods for applying these concepts infrastructure (and others types of) power systems have been proven in numerous applications. While these are different different than traditional methods, and require more skills and somewhat more labor, they are often essential in order to of meaningful performance improvement from the distribution achieve any type of system within a reasonable budget limit. This chapter served only as a summary of of modem modern distribution planning methods. Additional Additional details are found in the references below, particularly in those by Engel and Willis

REFERENCES T&D Company Inc., Electric Power ABB Power T &D Company Inc., Electric Power Transmission and Distribution Reference Book, Fifth Fifth Edition, Raleigh, Reference Raleigh, 1998, 1998. Tutorial, IEEE Power Engineering Engineering M. V. Engel, editor, Power Distribution Planning Tutorial, Society, 1992.

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Primary Distribution Planning and Engineering Interactions

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Recommended Practice for for Electric Institute of of Electrical and Electronics Engineers, Recommended Electric Power Distributionfor Industrial Plants Plants (the Red Book), Power Distribution for Industrial Book), Institute of of Electrical and Electronics Engineers, New York, 1994. 1994. Recommended Practice for for Design Design of Institute of of Electrical and Electronics Engineers, Recommended of Reliable Industrial Industrial and Commercial Power Systems of Reliable Commercial Power Systems (the Gold Book), Institute of Electrical and Electronics Engineers, New York, 1991. Power Distribution Distribution Planning Planning Reference Reference Book, Marcel Dekker, New York, H. L. Willis, Power 1997. Power Outages United States Department of of Energy, Power Outages and and System Trouble (POST) (POST) Report, March 2000, Washington DC.

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11 11 Equipment Condition Assessment 11.1 INTRODUCTION INTRODUCTION

Assessment of the condition of of power system equipment, and decisions about what service and utilization is appropriate for each unit, begins with the inspection, testing, and diagnostic methods covered in Chapter 6. These basic tools for condition assessment provide the data, which when interpreted, leads to decisions regarding: 1.

Whether the unit is suitable for service or must be withdrawn and repaired,

2.

Whether more comprehensive, invasive, and expensive tests are justified before making such a decision.

3.

The how it deteriorates with age and The condition of the unit - if and and how age and service and its viability for future service.

This chapter discusses the testing needs and approaches for each major class of of of power system equipment, and how they are organized organized into a program of condition assessment. Sections 11.2 through 11.6 discuss in tum turn the testing and diagnostic needs of of various categories of of equipment, in sections for transformers, breakers and switchgear, underground cables and equipment, overhead lines and equipment, and service transformers. Section 11.7 discusses discusses assessment assessment analysis methods - using test results to reach conclusions about equipment condition - and and and draws some conclusions about what testing and diagnostics can and cannot do. Section 11.8 concludes with a comparison of of needs among the various classes of of equipment, and a summary of of key points. 337 Copyright © 2001 by Taylor & Francis Group, LLC

338

Chapter 11

To be effective, inspection, diagnostics, diagnostics, and testing must be applied in a carefully carefully coordinated program that also uses the results from system operation (trouble reports) to identify identify overall equipment condition and performance, and that prioritizes preventive maintenance, repair, rebuilding, and replacement. Optimum results are derived by then loading equipment to levels determined based on its assessed assessed condition, the loss of of lifetime caused by the usage, and the available economic alternatives. Procedures Procedures for organizing organizing and managing such 15. This chapter focuses on programs will be discussed in chapters 12 12 and 15. condition assessment inspection, diagnostics, and testing methods themselves. 11.2 POWER POWER TRANSFORMERS TRANSFORMERS

Transformers are one of of the basic building blocks of of power systems. They alter constitution of of alternating current power passing through through the voltage-current constitution them, essentially changing the economy of of scale of of transmission of of the power from from one side of of the transformer to the other. other.'I category of of Power transformers at distribution substations constitute a major category distribution equipment. Generally, Generally, their capacity is summed throughout a capability of of that system. system, or at a substation, in order to determine the capability of many indications that they are considered considered the key aspect of of a This is only one of distribution system. Regardless, large power transformers are a major concern to any electric utility when it comes to reliability evaluation, because each one feeds large numbers of of customers and its replacement would involve a of time and expense. Much of of the contingency planning of of considerable amount of power systems relates to concerns about transformer loading limits, limits, and arrangements arrangements for contingency operation when one fails (see Chapters 8, 9, and 13). Transformer Transformer Aging and Deterioration Transformers "age" "age" in the sense that the strengths of of their components of chronological time, time in service and loading, and deteriorate as a function of due to severe abnormal events like through-faults and switching surges. The amount of of load served has a great deal to do with the rate of deterioration. Chapter 7 discusses in detail aging and loss of of life with service time. Many aspects aspects of of a transformer deteriorate with time: 1) 1) the insulation level of of of its core its windings; 2) its oil and its bushings; 3) the mechanical strength of stack and internal bracing and electrical connections; 4) the desired chemical stack and physical properties of of its materials (anti-oxidants in the oil, corrosion corrosion resistance of of paints, flexibility of of insulation, etc.). However, deterioration of of the insulation (of (of both winding winding and the oil itself) is the major area of of concern, and the predominant area evaluated, to determine a transformer's "condition." There are several reasons for the focus on internal insulation strength. First, I

See the Power Distribution Distribution Planning Planning Reference Reference Book, Chapter 7.

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Equipment Condition Assessment

339

a core winding insulation failure will not only prevent the transformer from doing its job, but probably lead to a large fault causing if causing very severe damage if not catastrophic failure. Bushing failures, corrosion, and other types of of deterioration can lead to failure of of the device, but rarely cause such high levels of damage. of Secondly, many other defects, when found, can be repaired or replaced rather quickly and inexpensively. Bushings can be replaced, tap changers repaired, and most non-core/winding related equipment serviced while the unit is left in place but de-energized. However, the winding insulation is both the most difficult difficult and the most expensive item to repair in a transformer. The unit must be withdrawn from service for a long period of of time and returned to a factory or refurbishment refurbishment center for what is essentially a complete rebuild. The insulating oil in a transformer, if significantly degraded, can be reconditioned or replaced. This will improve the oil and have a positive effect effect on the condition of of the winding cellulose insulation. But in some cases the winding insulation is sufficiently sufficiently deteriorated so that replacing the oil alone will not necessarily make a satisfactory improvement in the transformer as a whole. For all these reasons, the main focus of of power transformer condition assessment is on insulation strength, the various tests focusing on direct (measures (measures of of dielectric strength) and indirect (measures of contaminates, of determining the winding and oil insulation dissolved gas analysis) means of strength. However, other portions and aspects of of the unit should be checked regularly and maintained as needed. Acceptance Tests

New units are usually tested for insulation resistance, dielectric strength, turns ratio, amount of of losses, and run through AC hi-pot and power factor tests. They may be subjected to load cycle (thermal tests). Acceptance tests are not a factor in condition assessment assessment of of older equipment and will not be discussed here. Routine Transformer Inspection Routine Transformer

Routine physical inspection of transformers includes : Examining the exterior of of the unit for signs of of leakage or corrosion corrosion of of the case; examining radiator joints and grounding straps, etc., for cracked or dirty bushings, for damage (vandalism, weather), deterioration (paint chalking), and loosening of of brackets brackets or seals for attached sub-components (radiator fans, pressure sensors). It should also of ancillary devices such as oil pumps, fans, include testing the operation of changer mechanism and its control system. pressure relief valves, and the tap changer of inspection inspection should be done annually, if if not on a more frequent basis. This level of Overall, inspection tends to focus on aspects of transformer other than of the transformer insulation strength and winding condition. Inspection Inspection may include viewing the unit through an infra-red scanner scanner to enhance detection of of hot-spots caused by of incoming lines, leakage current, or other similar loose terminations of flaws. Similarly, it can include enhanced "audible "audible noise" analysis developing flaws. Copyright © 2001 by Taylor & Francis Group, LLC

340

Chapter 11

using a spectrum analyzer and pattern recognizer programmed to identify of trouble. acoustic signatures indicative of operating records Routine inspection should include a thorough review of all operating (temperature, pressure, load records) since the last routine inspection, with particular attention paid to abnormal events such as nearby lightning strikes, through faults, and storm damage. Depending on the results of of these inspections, follow up tests or diagnostics aimed at determining more precisely the condition and any necessary maintenance may be required. Routine or Periodic Tests

Along with routine routine inspection, certain tests are done on a periodic basis. These tests have two uses: 1.

if any measured values "Good to go" evaluation. The tests determine if deviate from their permissible or recommended ranges. This indicates a need for further testing or for maintenance, and caution in using the device at high loadings. Values above a certain event lead to recommendations that the unit be withdrawn from service.

2.

Condition monitoring. Periodic values are compared to identify identify long term trends - a particular value (e.g., dissolved methane in the the oil) be below the the maximum permitted - but but significantly higher could still be than its value in the last test, indicating a possible problem just beginning to develop.

of the most common periodic tests and diagnostics for a transformer focus Many of of insulation strength, or look for the products or on measuring some aspect of signs of of insulation insulation and/or oil deterioration. Table 11.1 lists the periodic inspections and tests that are done on power power transformers. The frequency of of tests shown are the authors' impressions of of typical industry practice (not necessarily recommended practice) with regard to units that are not thought to be high risk. of having problems or a high potential for risk. Units that are suspected of if failure should be checked much more often - in extreme cases on a daily basis if not continuously (with real time monitoring). Four Categories of Risk/Recommended Evaluation

C57-1004-1991 classifies oil-filled oil-filled power transformers into four IEEE Standard C57 -I 004-I99Iclassifies categories of risk based on the results of of dissolved combustible categories or conditions of of the four categories, the standard then gases tests in their oil. Within each of recommends specific inspection and test intervals that vary depending on the rate of of change of the gas content as measured from interval to interval. It also of units and the time when they should be contains recommendations recommendations for use of

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Equipment Condition Assessment

341

Table 11.1 11.1 Inspections, Tests, and Diagnostics Performed on Power Power Transformers Monitor for for ... ... Liquid level Load current Temperature Voltage

Continuously Continuously Continuously Continuously

Inspections and Tests Insoections Exterior for signs of of damage, deterioration Interior for signs of of damage, deterioration Ground connections

Lightning arresters arresters Protective devices and alarms Radiators, pumps, valves, and fans

function Tap changer function Other exterior ancillary ancillary devices

Routinely, quarterly -10 years 55-10 Semi-annually Semi-annually Semi-annually Semi-annually Semi-annually Annually

Solid Insulation Insulation C) Hi-pot (A (AC) Induced voltage resistance Insulation resistance Power factor Polarization index and recovery voltage Insulating Oil Acidity Color analysis

Dielectric strength Interfacial tension Power factor TCGA When Condition Is Suspect All inspections and tests above DGA (gas (gas chromatography) Insulation resistance TTR

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5 years years

years 5 years years 1 -- 33 years 1I -- 33 years years 1-3 1 - 3years years

Annually Annually Annually

Annually 1-3 1 - 3years years Annually

Immediately

Problem identification identification Problem If winding winding faults suspected If If winding faults suspected suspected If

342

Chapter 11

C57.1 04-1991 Power Transformer Transformer Risk Conditions Table 11.2 IEEE Standard C57.104-1991 Conditions Condition

Meaning Transformer Transformer is is operating operating properly. properly. Greater than normal gassing. Suspected Suspected higher deterioration rate. rate. Additional monitoring and testing is warranted. High High level level of of decomposition has almost certainly occurred. Internal faults are likely. likely. Periodic gas analysis should be used to establish a trend. The unit may need to be scheduled for repair. Internal Internal faults are very likely. Continued operation may result in failure.

1 2 3

4

Table Based on TCGA Table 11.3 Summary of of Risk Categories Categories and Recommended Actions Based TCGA Tracking, from IEEE Standard C57.104-1991 Risk Condition

Defined by TDCG TDCG (ppm)

Rate of of Increase Increase (ppm/day) . . .

< 720 10

2

< 30

30 >30

3

< 10

1920 -4630 1920-4630

Means Operating Means Recommendations of of ... ...

Schedule an outage to check unit, unit, and test monthly until then. DGA tests. Exercise unit. Exercise extreme caution in use of of unit, and test weekly

> 30 >30

---------------------------------------> 4630

4

Exercise extreme caution and test weekly, schedule repair soon. Consider removal from service now, and test daily until then

< III:>. (!)III ... '0

ft Eo. 20 CII~ E Q.

6

"'0.

.g

9

III

12 2

C

l!

I-

2

1C

15+ 15+

15+

15+

-;;

Breaker A0121 A0121 Option 2: Partial Service Reliability Improvement: 2639 Cost: $2,250 Bang/Buck -1.17

Decide rather

ion 3 ion 2

Breaker A0121 A0121 Option 3: Full Service Reliability Reliability Improvement: 4,222 Cost: $13,000 Bang/Buck - 0.32 0.32

AD 121, viewed marginal Figure 12.4 12.4 The three possible possible projects projects for breaker A0121, viewed as marginal is infra-project intra-project evaluation ~ decisions. This is - comparison of project alternatives that all fall within one equipment unit or set of equipment -~ 1S as opposed to inter-project inter-project comparison -~ comparing comparison comparing projects projects applied to one one unit of equipment to those on others.

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Prioritization Methods for O&M

391

described here, it provides a big improvement. The "chain" of of options shown in Figure 12.4 basically reduces a decision with multiple outcomes (which of of four alternatives do I choose?) to a series of binary (yes-no) decisions. It simplifies performing the decision-making process with a formal (Le., (i.e., rigorous, repeatable, procedure that essentially performs a series of of binary documentable, defendable) procedure evaluations (this is better than that). It also illustrates a key point. Doing nothing should always be the basis for comparison: all activities should justify themselves against against a "zero base." Looking at Table 12.7, note that the scores for these three options (last column), the lowest cost option, 8c has the same as it did in Table 12.6 - a score of expected reduction reduction over $6,750). But option of 1.68 ($11,340 customer minutes expected 8b has a score of of only 1.17, rather than 1.55 as evaluated in Table 12.6. While project 8b looks good enough when viewed on its own, viewed as a decision to spend $2,250 more than option 8c to gain the improvement it gives over 8c, it as good - definitely not good enough to gain approval in does not look quite as Table 12.3. That $2,250 is not nearly as effective in improving reliability as the $6,750 spent on only buying option 8c. Similarly, when viewed as a marginal looks very inefficient, inefficient, with a sore of of only .32. option, option 8 itself itselflooks of all projects from Table Table 12.8 shows the ReM RCM evaluation and ranking of 12.3 with these three projects substituted for project 8. Note that 8c, with its of merit score of of 1.68, makes it into the "winners" category. Projects 8b figure of and 8 fall far far below the approval limit - their additional additional cost over 8c 8c is definitely not justifiable based on their additional benefit. benefit. The recommended action, then, is to select to perform only "testing and replacement as found needed" on this breaker. What got bumped off off the list to make room for project 8b? In this case, nothing. Instead, whereas originally the utility could just afford afford to buy the top ten projects, it can now not quite afford afford to buy all of of the final projects on the approval list (#32, Hillside substation feeders - testing and and replacement as found needed). By the time it gets down to that item in Table 12.8, it is $6,7500 of having enough to fund this project completely. Prorating that project by short of assuming that some small portion could be deleted with proportional impact on results, indicates that this change in using alternatives for project 8 results in a .03% improvement overall. Using the approval limit's marginal cost of of reliability ($I.4l/customer ($1.41/customer minute) the additional reliability wrought by this improvement over the results of ifit of Table 12.3 would cost the utility another $859 to buy if it stuck to the method used in Table 12.3. This small improvement may hardly seem worth the effort effort of of going through of the discussion above was to introduce the this analysis. However, the point of of extending the ReM RCM evaluation to deciding how to maintain each unit concept of of of equipment, not just what gets maintained. By evaluating options in this the ReM manner - letting the RCM decided what is is done, not just what equipment is

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392

Chapter 12

Table 12.8 12.8 Projects Evaluated By ReM RCM Ranking, Including Two Options for Project 8 Project Equipment Equipment Number Type 18 4 2 I1 20 25 21 21

Work Proposed

# Cust

UG cables, feeder EC06 40 MVA MY A transf. DT03 40 MYA transf. transf ECO 40MVA EC01I transf. EC03 40 MVA MY A transf. UG cables, net DT3B Poles, CE district UG cables, net DTJA DT3A

Reduced Cust-Min Out PWSum Cost "Bang! 'Bang/ Yr. 0 Next +2yr. +2 yr. Cust-min (yr. 0) Buck"

Replace All 2,200 121440 128436 Test, Follow up 4,612 44275 48703 Recond. Oil/Serve. 7,800 74880 81432 Rebuild Complete 10,899 222343 235749 245 67032 71207 Replace Complete 80,134 575234 625675 Test, Replace 340 22195 Test, Replace 25198 8e 11300 # AOl21 Test, Replace 3797 4231 8c HV breaker Replace breaker #A01 21 3 MY A transf. transf. JT235 Test, Follow up 842 40 MVA 5982 6606 Test, Replace Replace feeders 32 Riverside sub feeders 28,093 177997 199134 199134 --------------------- Approval Limit Based on Budget 33 Hillside sub feeders Test, Replace 14,004 108895 121826 31 Oldtown sub feeders 22,789 98448 110139 Test, Replace 34 Central sub feeders Selected Replace 28,345 131634 143981 Rebuild 43,000 385968 415741 Complete Rebuild 35 Farmton substation substation 8b HV 11300 949 973 HV breaker AOl21 breaker ##A0121 Partial Service Service 27 OH feeder BN05 Inspection, Replace 1,609 5870 6567 19 UG cables, feeder EC07 Test, Replace 592 5570 6348 HY breaker # EC03 Complete Service 10,899 HV 6521 5 6043 1376 2,200 10 LV breaker #EC06 Complete Service 1493 7,800 4324 4666 6 HV HV breaker # ECO 1 Complete Service 1,578 24 OH feeder EC 17 17 Inspect, Replace 10680 11752 LY breaker #ES06 Complete Service 1,681 9 LV 1141 1052 2,091 16 LV LV breaker #DT3N # DT3 N Complete Service 2,091 81 891 811I 13 LV LY breaker #NB03 Complete Service 745 808 1,191 HV breaker breaker ##AQ A0121 Complete Service Service 11,300 8 HV Complete 1519 1557 12 1 Inspection, Replace 1,389 29 OH feeder CT05 4534 5072 4390 4911 26 OH feeder BN04 Inspection, Replace 1,345 4911 662 #CN 1A 1,058 718 LY breaker #CN1 Complete Service 14 LV A 42,300 kY circuits 34 & 37 Test, Replace 5198 5708 23 69 kV 407 12 LV breaker #NB02 Complete Service 650 441 Inspection, Replace 1,555 4777 5344 30 OH feeder JM07 394 11 LV breaker #NB01 #NBO I Complete Service 580 363 2727 Inspection, Replace 1,671 3051 CT 14 iin 28 OH feeder CTl4 15 LV LY breaker #CN2A Complete Service 891 310 342 22 OH feeder BN06 Inspect, Replace 950 2508 2856 634 7 HV breaker # 2221 Complete Service 379 21 351 30 17 LV breaker #DT2N 112 34 Complete Service

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346789 $27,000 130779 $11,000 219012 $22,000 $22,000 636315 $65,000 $65,000 192144 $43,000 1682718 $610,000 67373 $31,000 11340 $6,750 $6, 750 4612 17729 $11,000 7163 217621 533491 $335,000

135502 52681 87461 87461 249132 75341 672069 27777

12.84 11.89 9.96 9.79 4047 4.47 2.76 2.17

1.68 1.61 .61 .59 1.59 - - - - - - - - - - - - - - - - - - - _. 133136 120364 155199 443829

326379 326379 295068 386928 1119637

$219,000 $210,000 $210,000 $310,000 $905,000

1.49 .49 1041 .41 1.25 .25 1.24 .24

1608

4222

$13,000

1.17 1.03 0.94 0.80 0.62 0.57 0.54 0.47 0.37 0.33 0.32

5543 5367 770 6169 473 5840 422 3334 371 3153 405 37

13588 13158 1932 15332 1187 14317 1059 8174 919 7632 1021 90

$43,000 $43,000 $6,500 $70,000 $70,000 $6,500 $86,000 $6,500 $56,000 $6,500 $58,000 $22,000 $6,500

0.32 0.31 0.31 0.30 0.30 0.22 0.18 0.17 0.16 0.15 0.14 0.13 0.05 0.01

1005

2639

$2,250 52,250

7176 7014 6969 1602 4987 12714 1224 963 867

17592 16964 17556 4018 12564 31555 3069 2394 2175

$17,000 $18,000 $18,000 $22,000 $22,000 $6,500 $22,000 $58,000 $6,500 $6,500 $6,500 $6,500

393

Prioritization Methods for O&M Table 12.9 Projects I1 and 35 with Multiple Multiple Alternatives Project Equipment Equipment Project Number Type

Work Proposed

# Cust

ReducedCust-Min Cust-Min Out Reduced Out

Yr.O Yr. 0

Next

PWSum Cost Bang! Bang/ +2 yr. Cust-min (yr. 0) Buck

For Project 11 Id 40 MV A Iransf. MVA transf. EC03 MV A transf. Ic 40 MVA transf. EC03 Ib 40 MV A transf. MVA transf. EC03 A transf. transf. EC03 1I 40 MV MVA

Test, Replace 10899 Complete Service Service 10899 Recond. Oil/Serve. Oil/Serve. 10899 Rebuild Complete Complete 10899

104632 115095 124497 309060 41853 41853 42899 44315 116357 26158 26812 27697 72723 52624 138174 49700 50943

$11,000 $10,000 $17,000 $27,000

28.10 11.64 4.28 5.12

For 35d 35c 35b 35

Test, Replace 43000 Servo Serv. Transf. Only 43000 Full Service 43000 Complete Rebuild 43000

181632 206297 227473 551552 $195,000 36326 37235 38463 100993 $65,000 81734 83778 86542 227234 $300,000 86275 88432 91350 239858 $345,000

2.83 1.55 0.76 0.70

Project 35 substation Farmton substation Farmton substation substation Farmton substation substation Farmton substation

17) For Project 99 (example for 99 - 17) 9b LV breaker #ES06 Test, Replace LV breaker #ES06 Complete Service 9

1681 1681

637 414

716 425

785 439

1918 1152

$1,100 $5,400

1.74 0.21

maintained, meaning an improvement in the total value obtained by the utility can be made. As will will be shown below when the concept is extended to all projects, the resulting savings are significant. Intra- vs. inter- project alternatives evaluation

Tables 12.6 - 8 showed one example of letting RCM determine what should be 12.6-8 done to a unit of equipment. equipment. The The earlier "optimizations" - those carried out out in section 12.3 - basically decided only among projects where it had had already been decided what would be done to each unit. Comparison like that, where decisions about what maintenance will be done has already been made, is called Inter-Project Alternatives Evaluation. By contrast, evaluating the possible Inter-Project maintenance options on one unit of of equipment to the possible maintenance Intra-Project Alternatives Evaluation. It options on others unit is termed Infra-Project applies the optimization to a broader range of of options and thus provides an improvement. Comprehensive Example Using Intra·Project Intra-Project Optimization

Table 12.9 lists three alternatives to project 1 and four for project 35 35 - the original and two and three alternatives respectively, for each. Also shown is one of splitting the nine LV breaker projects (numbers 9 through 17 in example of Table 12.1) into two alternatives. In the original list (Table 12.1, optimized in Table 12.3) nine LV breakers were listed for "full service" at $6,500 each. Here, an option - inspect and and replace (as (as found needed) - is an alternative at only $1,100 in cost but with less effective reliability improvement. improvement. All of of these figured as marginal costs and marginal improvements and options are shown figured grouped together as sets of of ordered, marginal decisions.

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Table 12.10 Projects Evaluated By RCM ReM Ranking Ranking Using "Intra-Project" Alternative Alternative Evaluation for Twelve Projects (#s 1,8,9-17, 1, 8, 9-17, and 35). Project Equipment Number Type

Work Proposed

Id 40 MVA MV A transf. EC03 Test, Replace 18 UG cables, feeder EC06 EC06 Replace All 4 40 MVA DT03 Test. MV A transf. DT03 Test, Follow up Ie 40 MVA MV A transf. transf. EC03 Complete Service Ic 40 MVA MV A transf. ECO I1 Recond. Oil/Serve. 2 40 1I 40 MV A transf. MVA transf. EC03 Rebuild complete 20 UG cables, net DT3B Replace complete A transf. EC03 Recond. Oil/serve. IIbb 40 MV MVA 35d Farmton substation substation Test, Replace 25 Poles. Test, Replace Poles, CE district lOb LV breaker #EC06 Test, Replace 21 UG cables, net DT3A Test, Replace Test. Test, Replace 9b LV breaker #ES06 Test, Replace A0121 8c HV breaker # A01 21 3 40 MVA MV A transf. JT235 Test, Follow up 32 Riverside sub feeders Test, Replace Servo 35c Farmton substation Serv. Transf. Only - - - - - - - - - - - - - - - - - -- -- Approval 33 31 16b 34 13b 8b 14b 27 19 5 35d 13 35 12b Il iI b 6 24 8 29 26 10 23 9 30 16 28 14 22 15b I5b 12 11 II IS 15 17b 7 17

Hillside sub feeders Oldtown sub feeders LV breaker #DT3N Central subs!. subst. feeders LV breaker #NB03 A0121 HV breaker # A01 21 L V breaker #CN 1A LV breaker #CN1 OH feeder BN05 UG cables, feeder EC07 HV breaker # EC03 Farmton substation LV breaker #NB03 Farmton substation LV breaker #NB02 #NB02 #NBO I L V breaker #NB01 LV HV breaker # ECO I1 HV OH feeder EC 17 17 AO 1221I HV breaker # A01 CT05 OH feeder CT05 OH feeder BN04 LV breaker #EC06 69 kV circuits circuits 34 & & 37 LV breaker #ES06 OH feeder JM07 LV breaker #DT3N CT 14 OH feeder CTl4 LV breaker #CN1 #CN I A OH feeder BN06 LV breaker breaker #CN2A LV breaker #NB02 LV breaker breaker #NBO #NB01I LV breaker #CN2A LV breaker #DT2N HV breaker # 2221 21 LV breaker #DT2N

Test, Replace Test, Replace Test, Replace Selected Replace Test, Replace Partial Service Test, Replace Inspection, Replace Test, Replace Complete Service Full Service Complete Service Complete Rebuild Test, Replace Test, Replace Complete Service Inspect, Replace Complete Service Inspection, Replace Inspection, Replace Complete Service Test, Replace Complete Service Inspection, Replace Complete Service Inspection, Replace Complete Service Inspect, Replace Test, Replace Complete Service Complete Service Complete Service Test, Replace Complete Service Complete Service

# Cust

Reduced Cust-Min Out PWSum Cost Bang! Bang/ Yr. 0 Next +2yr. +2 yr. Cust-min (yr. 0) Buck

10899 104632 115095 124497 309060 $11,000 28.10 28.10 2200 121440 128436 135502 346789 346789 $27,000 $27,000 12.84 12.84 4612 44275 4612 52681 130779 $11,000 1I.89 11.89 48703 10899 41853 11.64 42899 44315 116357 $10,000 11.64 7800 74880 81432 87461 219012 $22,000 9.96 9.96 10899 49700 50943 52624 138174 $27,000 5.12 5.12 245 75341 192144 $43,000 4.47 4.47 67032 71207 27697 72723 $17,000 $17,000 4.28 10899 26158 4.28 26812 43000 43000 181632 206297 227473 551552 $195,000 $195,000 2.83 2.83 672069 1682718 $610,000 $610,000 2.76 2.76 80134 575234 625675 6720691682718 1027 1027 2510 $1,100 2200 2.28 834 938 2.28 27777 67373 $31,000 2.17 340 22195 2.17 25198 785 1918 1918 1.74 $1,100 1.74 1681 716 637 4612 11340 4612 $6,750 11300 4231 $6,750 1.68 1.68 3797 4231 842 7163 17729 $11,000 1.61 1.61 6606 5982 28093 177997 1.59 1.59 1 77997 199134 217621 533491 $335,000 1.55 43000 36326 36326 37235 38463 100993 $65,000 1.55 43000 Limit Based on Budget----- --- - - -----------. Budget— 14004 108895 1.49 326379 $219,000 1.49 108895 121826 133136 326379 $210,000 22789 98448 110139 120364 295068 $210,000 1.41 $1,100 2091 1505 1.37 1505 492 625 564 28345 131634 143981 155199 386928 $310,000 1.25 1.25 1191 1359 $1,100 556 1.24 452 1.24 508 1.17 1005 $2,250 1005 2639 $2,250 11300 949 973 1207 $1,100 1207 1058 401 494 1.10 1058 451 1609 7176 17592 $17,000 1.03 7176 $17,000 1.03 5870 6567 7014 16964 $18,000 0.94 $18,000 592 5570 6348 6969 17556 $22,000 10899 0.80 10899 0.80 6521 6043 6521 0.76 43000 81734 83778 86542 227234 $300,000 0.76 $5,400 0.74 311 816 1191 294 301 239858 $345,000 0.70 43000 86275 88432 88432 91350 239858 $1,100 304 $1,100 0.67 742 650 277 246 0.60 271 662 $1,100 0.60 220 580 247 12564 $22,000 4987 0.57 7800 4324 4666 $58,000 0.54 12714 12714 31555 $S8,000 0.54 1578 10680 11752 1578 4222 $13,000 0.32 11300 1519 1557 1608 1557 5543 0.32 1389 13588 $43,000 4534 5072 $43,000 0.31 1345 5367 13158 13158 4390 4911 0.28 $5,400 0.28 574 1508 2200 542 556 0.22 6169 15332 $70,000 42300 5198 5708 439 $5,400 0.21 1152 $5,400 0.21 1681 425 414 14317 0.17 14317 $86,000 1555 5840 4777 5344 1555 $5,400 889 0.16 338 2091 320 328 3334 8174 0.15 8174 $56,000 0.15 1671 2121 2727 3051 276 $5,400 0.13 725 1058 261 267 3153 7632 $58,000 0.13 950 2508 2856 $1,100 579 0.11 241 891 188 217 170 $5,400 0.08 0.08 445 650 6S0 160 164 151 $5,400 0.07 397 580 143 147 $5,400 0.06 130 340 $5,400 0.06 891 122 125 $1,100 0.05 24 112 57 18 21 $22,000 0.05 1021 $22,000 634 405 3S1 351 379 $5,400 0.01 $5,400 13 33 12 12 112

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A different different set of of decisions Table 12.10 shows the result of of an RCM ranking based on customer-minutes that includes these alternatives added to the projects and alternatives used in Table 12.8 (including project 8's 8's options). Among the first eight projects at the top of of the list are all four of of the alternatives to project 1. 1. Although the RCM method had a list of of partial measures it could consider for this unit, it chose to "fully upgrade" project number 1 through selection of "fully of its alternatives 1Id, d, 1Ic, c, 1Ibb to 1. Thus, for that transformer it picked, in a serial, four-decision fashion, the full service as was originally selected in Table 12.3. often selected only an interim level of of But on other projects the prioritization often permitted maintenance. For project 35, alternatives 35d and 35c were selected. Alternatives 35b and 35 did not make the cut. Similarly, one low voltage breaker (9b, breaker ES06) makes the cut with testing and replacement as different than those obtained needed. As a result, these results are considerably different in Figure 12.3, even though the same 35 equipment units are being considered, and even though the same reliability index (customer minutes) is being used as the goal. Important differences in the results are given below. A 6.4% improvement improvement in results has been obtained

For the same budget, an increase of 264,326 customer minutes of interruption expecting to be avoided has been obtained. Gaining this in the original optimization (Table 12.3), would have cost the utility an extra $187,500 (264,326 customer-minutes at 1041 1.41 customer minutes per dollar).

Approval target is raised Approval Intra-project prioritization raises the bar for approval, because it gets more of the projects now being approved. Here, the "bang" per dollar from some of approval limit increases by nearly 10%, from 1.41 1.41 to 1.55. Better projects are being implemented. This increase in the target value (10%) is greater than the of increase in overall results (604%) (6.4%) because of the scree-shape scree-shape of the top part of the project mix mix - the the very best projects approved did did not change. More units of equipment equipment receive some improvement improvement

of units seeing some reliability improvement increases by over The number of 30%. Maintenance effort effort is spread around the system more. Smaller projects are being done Smaller Since this method tends to "spread around" the money on more projects, that means the limited budget is splintered into more, but smaller, projects. On average, they are of of greater greater average value compared to their cost.

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The optimization optimization selected selected "partial measures" measures" It is significant that in 40% of of the equipment units selected for some

maintenance, the RCM decided to maintain it by selecting only an interim measure. More significantly, in all but one case where it had the choice, it chose an interim measure. Full Implementation Implementation would do even better Table 12.10 applied prioritization using multiple alternatives alternatives for only thirteen of of thirty-five units of of equipment involved. involved. If a multiple alternatives approach is applied to all projects on the list, the improvement in figure of of merit obtained grows to about 10% or slightly more depending on details of of the reliability index used and how thoroughly project alternatives are represented. Such an example is beyond the scope of of what can be given here (it results in a list with over 110 entries). However, the concept of its execution is exactly as used above.

12.5 PRACTICAL PRACTICAL ASPECTS FOR IMPLEMENTATION

The foregoing examples, while comprehensive, simplified several of of the details needed when RCM is applied in actual practice in order to streamline the examples so that the major points could be made in a succinct manner. When applied to actual utility utility cases, the authors make the following following recommendations for reliability-centered prioritization. reliability-centered maintenance prioritization. Cost and Benefits Should Be Treated as Expectations

As discussed in Chapters 6, 11, and elsewhere throughout this book, equipment failure is a random process that cannot be predicted with accuracy on a singlesingleunit or small-lot basis except in a few very special cases. Similarly, both the cost of of maintenance and the benefits that maintenance of doing some types of maintenance provides, is probabilistic. probabilistic. For example, the category of of service "Inspect and Make Repairs as Found Necessary" will vary in both cost and benefits from unit to unit depending on what is found when inspection is carried out. This cannot be predicted accurately in advance for anyone any one unit of of equipment (a specific pole, a particular power transformer) but it can be predicted en masse over a large group of of units. Reliability-Centered Maintenance should be applied in this context: the failure rates being dealt with, the benefits expected expected from maintenance, and the costs of that service are all expectations, accurate and dependably forecast-able on a large-scale basis but determinable on an individual individual basis only as probabilistic expectations. expectations.

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Use Only Historically-Based Historically-Based Cost and Improvement Improvement Factors Factors

The failure rates for equipment, as a function of of condition as used for "before service" expectations of reliability, reliability, the improvement expected from various levels of of service applied to equipment of of various categories of of age/condition, and the cost of of various types of service should all be developed from historical data. For example, the entries in a table like Table 12.2 should be based, to the extent possible, on historical experience specific to the utility, or data from a large set of of samples published in a reputable reviewed technical journal. If If that should be developed developed by consultation with experts who is not possible, the data should have experience in such work.8 Represent Represent Improvements Improvements as Having Only Short-Term Impacts Impacts on Reliability Reliability

Even the most comprehensive service on a transformer, breaker, underground or overhead line will result in improvements that only last for a short time. Left overhead unattended after after the preventive maintenance, the device will return to its of time. The original "aged" failure rate condition in only a short period of improvements in reliability used as the RCM benefit should reflect this in a realistic sense. Overestimating the length of of time improvements make a positive impact will overemphasize overemphasize the value of of maintenance, leading to too much spending spending and a shortfall of expectations. of results versus expectations. Figure 12.5 illustrates the difference difference between between the impact that service might make, and replacement. Here, a 30-year old transformer can either be replaced or re-built. Replacement results in "like new" condition and it will take 30 years for expected failure rate to return to the level of just prior to replacement. of inspection, testing, and preventive maintenance, Performing any type of different impact. First, it does not result in "like new" condition however, has a different is somewhat less. Secondly, the the the improvement is and failure rate expectation expectation - the improvement does not last for 30 years, as replacement does, but for a much shorter time, as shown. Generally, noticeable improvements from service only for only 33-- 77 years. older units last for

Category-Based Equipment Equipment Use Category-Based Condition Maintenance Types Condition and Maintenance Expected RCM costs, as well as the benefits (reliability improvement gained) of preventive service and the cost from inspection, testing, and various grades of assigned to each category represent represent expectations for and improvement numbers assigned category. equipment-service combinations in that category. maintenance efforts efforts All equipment being considered for maintenance, and all maintenance that are being considered to be performed, are classified by these category 8 8

Many consultants can develop sets of good-looking numbers. numbers. Far fewer seem able to develop numbers that produce dependable results.

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Chapter 12 Replacement

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Replacement Replacement returns equipment to condition "like new" conditio

condition return to the same condition replacement as prior to rePlac~t

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